Temperature limited heater utilizing non-ferromagnetic conductor

ABSTRACT

A heater is described. The heater includes a ferromagnetic conductor and an electrical conductor electrically coupled to the ferromagnetic conductor. The ferromagnetic conductor is positioned relative to the electrical conductor such that an electromagnetic field produced by time-varying current flow in the ferromagnetic conductor confines a majority of the flow of the electrical current to the electrical conductor at temperatures below or near a selected temperature.

PRIORITY CLAIM

This patent application claims priority to U.S. Provisional Patent No.60/674,081 entitled “SYSTEMS AND PROCESSES FOR USE IN TREATINGSUBSURFACE FORMATIONS” to Vinegar et al. filed on Apr. 22, 2005, and toU.S. Provisional Patent No. 60/729,763 entitled “SYSTEMS AND PROCESSESFOR USE IN TREATING SUBSURFACE FORMATIONS” to Vinegar et al. filed onOct. 24, 2005.

RELATED PATENTS

This patent application incorporates by reference in its entirety eachof U.S. Pat. Nos. 6,688,387 to Wellington et al.; 6,698,515 to Karanikaset al.; 6,880,633 to Wellington et al.; and 6,782,947 to de Rouffignacet al. This patent application incorporates by reference in its entiretyeach of U.S. Patent Application Publication Nos. 2003-0102126 toSumnu-Dindoruk et al.; 2003-0205378 to Wellington et al.; 2004-0146288to Vinegar et al.; 2005-0051327 to Vinegar et al.; and 2005-0269313 toVinegar et al. This patent application incorporates by reference in itsentirety U.S. patent application Ser. No. 11/112,881 to Vinegar et al.

GOVERNMENT INTEREST

The Government has certain rights in this invention pursuant toAgreement No. ERD-05-2516 between UT-Battelle, LLC, operating underprime contract No. DE-ACO5-00OR22725 for the US Department of Energy andShell Exploration and Production Company.

BACKGROUND

1. Field of the Invention

The present invention relates generally to methods and systems forheating and producing hydrocarbons, hydrogen, and/or other products fromvarious subsurface formations such as hydrocarbon containing formations.Embodiments relate to temperature limited heaters used to heatsubsurface formations.

2. Description of Related Art

Hydrocarbons obtained from subterranean formations are often used asenergy resources, as feedstocks, and as consumer products. Concerns overdepletion of available hydrocarbon resources and concerns over decliningoverall quality of produced hydrocarbons have led to development ofprocesses for more efficient recovery, processing and/or use ofavailable hydrocarbon resources. In situ processes may be used to removehydrocarbon materials from subterranean formations. Chemical and/orphysical properties of hydrocarbon material in a subterranean formationmay need to be changed to allow hydrocarbon material to be more easilyremoved from the subterranean formation. The chemical and physicalchanges may include in situ reactions that produce removable fluids,composition changes, solubility changes, density changes, phase changes,and/or viscosity changes of the hydrocarbon material in the formation. Afluid may be, but is not limited to, a gas, a liquid, an emulsion, aslurry, and/or a stream of solid particles that has flow characteristicssimilar to liquid flow.

Heaters may be placed in wellbores to heat a formation during an in situprocess. Examples of in situ processes utilizing downhole heaters areillustrated in U.S. Pat. Nos. 2,634,961 to Ljungstrom; 2,732,195 toLjungstrom; 2,780,450 to Ljungstrom; 2,789,805 to Ljungstrom; 2,923,535to Ljungstrom; and 4,886,118 to Van Meurs et al., each of which isincorporated by reference as if fully set forth herein.

Application of heat to oil shale formations is described in U.S. Pat.Nos. 2,923,535 to Ljungstrom and 4,886,118 to Van Meurs et al. Heat maybe applied to the oil shale formation to pyrolyze kerogen in the oilshale formation. The heat may also fracture the formation to increasepermeability of the formation. The increased permeability may allowformation fluid to travel to a production well where the fluid isremoved from the oil shale formation. In some processes disclosed byLjungstrom, for example, an oxygen containing gaseous medium isintroduced to a permeable stratum, preferably while still hot from apreheating step, to initiate combustion.

A heat source may be used to heat a subterranean formation. Electricheaters may be used to heat the subterranean formation by radiationand/or conduction. An electric heater may resistively heat an element.U.S. Pat. No. 2,548,360 to Germain, which is incorporated by referenceas if fully set forth herein, describes an electric heating elementplaced in a viscous oil in a wellbore. The heater element heats andthins the oil to allow the oil to be pumped from the wellbore. U.S. Pat.No. 4,716,960 to Eastlund et al., which is incorporated by reference asif fully set forth herein, describes electrically heating tubing of apetroleum well by passing a relatively low voltage current through thetubing to prevent formation of solids. U.S. Pat. No. 5,065,818 to VanEgmond, which is incorporated by reference as if fully set forth herein,describes an electric heating element that is cemented into a wellborehole without a casing surrounding the heating element.

SUMMARY

Embodiments described herein generally relate to systems, methods, andheaters for treating a subsurface formation. Embodiments describedherein also generally relate to heaters that have novel componentstherein. Such heaters can be obtained by using the systems and methodsdescribed herein.

In some embodiments, the invention provides a heater, including: aferromagnetic conductor; and an electrical conductor electricallycoupled to the ferromagnetic conductor, wherein the ferromagneticconductor is positioned relative to the electrical conductor such thatan electromagnetic field produced by time-varying current flow in theferromagnetic conductor confines a majority of the flow of theelectrical current to the electrical conductor at temperatures below ornear a selected temperature.

In some embodiments, the invention provides a method for controlling aheater in a subsurface formation, including: assessing an electricalcharacteristic of the heater in the subsurface formation, the heaterbeing configured to heat at least a portion of the formation, the heaterincluding: a ferromagnetic conductor; and an electrical conductorelectrically coupled to the ferromagnetic conductor, wherein theferromagnetic conductor is positioned relative to the electricalconductor such that an electromagnetic field produced by time-varyingcurrent flow in the ferromagnetic conductor confines a majority of theflow of the electrical current to the electrical conductor attemperatures below or near a selected temperature; comparing theassessed electrical characteristic to predicted behavior for theelectrical characteristic; and controlling the heater based on thecomparison.

In some embodiments, the invention provides a heater, including: anelectrical conductor coupled to a ferromagnetic material, the heaterbeing configured to provided electric resistance heating, and the heaterhaving dimensions such that a majority of the electric resistance heatoutput is generated in the electrical conductor; and wherein theferromagnetic material is configured to substantially concentratetime-varying electrical current flow to the electrical conductor attemperatures below or near a selected temperature.

In certain embodiments, the invention provides one or more systems,methods, and/or heaters. In some embodiments, the systems, methods,and/or heaters are used for treating a subsurface formation.

In further embodiments, features from specific embodiments may becombined with features from other embodiments. For example, featuresfrom one embodiment may be combined with features from any of the otherembodiments.

In further embodiments, treating a subsurface formation is performedusing any of the methods, systems, or heaters described herein.

In further embodiments, additional features may be added to the specificembodiments described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

Advantages of the present invention may become apparent to those skilledin the art with the benefit of the following detailed description andupon reference to the accompanying drawings in which:

FIG. 1 depicts an illustration of stages of heating a hydrocarboncontaining formation.

FIG. 2 shows a schematic view of an embodiment of a portion of an insitu conversion system for treating a hydrocarbon containing formation.

FIG. 3 depicts a schematic of an embodiment of a Kalina cycle forproducing electricity.

FIG. 4 depicts a schematic of an embodiment of a Kalina cycle forproducing electricity.

FIG. 5 depicts a schematic representation of an embodiment of a systemfor producing pipeline gas.

FIG. 6 depicts a schematic representation of an embodiment of a systemfor producing pipeline gas.

FIG. 7 depicts a schematic representation of an embodiment of a systemfor producing pipeline gas.

FIG. 8 depicts a schematic representation of an embodiment of a systemfor producing pipeline gas.

FIG. 9 depicts a schematic representation of an embodiment of a systemfor producing pipeline gas.

FIG. 10 depicts a schematic representation of an embodiment of a systemfor treating the mixture produced from the in situ conversion process.

FIG. 11 depicts a schematic drawing of an embodiment of areverse-circulating polycrystalline diamond compact drill bit design.

FIG. 12 depicts a schematic representation of an embodiment of amagnetostatic drilling operation to form an opening that is anapproximate desired distance away from a drilled opening.

FIG. 13 depicts an embodiment of a section of a conduit with two magnetsegments.

FIG. 14 depicts a schematic of a portion of a magnetic string.

FIG. 15 depicts an embodiment of a freeze well for a circulated liquidrefrigeration system, wherein a cutaway view of the freeze well isrepresented below ground surface.

FIG. 16 depicts a schematic representation of an embodiment of arefrigeration system for forming a low temperature zone around atreatment area.

FIG. 17 depicts a schematic representation of a double barriercontainment system.

FIG. 18 depicts a cross-sectional view of a double barrier containmentsystem.

FIG. 19 depicts a schematic representation of a breach in the firstbarrier of a double barrier containment system.

FIG. 20 depicts a schematic representation of a breach in the secondbarrier of a double barrier containment system.

FIG. 21 depicts a representation of a protective sleeve strapped to acanister of a freeze well.

FIG. 22 depicts a schematic representation of a fiber optic cable systemused to monitor temperature in and near freeze wells.

FIG. 23 depicts a schematic view of a well layout including heatinterceptor wells.

FIG. 24 depicts an embodiment of a ball type reflux baffle systempositioned in a heater well.

FIG. 25 depicts a schematic representation of an embodiment of adiverter device in the production well.

FIG. 26 depicts a schematic representation of an embodiment of thebaffle in the production well.

FIG. 27 depicts a schematic representation of an embodiment of thebaffle in the production well.

FIG. 28 depicts an embodiment of a dual concentric rod pump system.

FIG. 29 depicts an embodiment of a dual concentric rod pump system witha 2-phase separator.

FIG. 30 depicts an embodiment of a dual concentric rod pump system witha gas/vapor shroud and sump.

FIG. 31 depicts an embodiment of a gas lift system.

FIG. 32 depicts an embodiment of a gas lift system with an additionalproduction conduit.

FIG. 33 depicts an embodiment of a gas lift system with an injection gassupply conduit.

FIG. 34 depicts an embodiment of a gas lift system with an additionalcheck valve.

FIG. 35 depicts an embodiment of a gas lift system that allows mixing ofthe gas/vapor stream into the production conduit without a separategas/vapor conduit for gas.

FIG. 36 depicts an embodiment of a gas lift system with a checkvalve/vent assembly below a packer/reflux seal assembly.

FIG. 37 depicts an embodiment of a gas lift system with concentricconduits.

FIG. 38 depicts an embodiment of a gas lift system with a gas/vaporshroud and sump.

FIG. 39 depicts an embodiment of a device for longitudinal welding of atubular using ERW.

FIG. 40 depicts an embodiment of an apparatus for forming a compositeconductor, with a portion of the apparatus shown in cross section.

FIG. 41 depicts a cross-sectional representation of an embodiment of aninner conductor and an outer conductor formed by a tube-in-tube millingprocess.

FIGS. 42, 43, and 44 depict cross-sectional representations of anembodiment of a temperature limited heater with an outer conductorhaving a ferromagnetic section and a non-ferromagnetic section.

FIGS. 45, 46, 47, and 48 depict cross-sectional representations of anembodiment of a temperature limited heater with an outer conductorhaving a ferromagnetic section and a non-ferromagnetic section placedinside a sheath.

FIGS. 49, 50, and 51 depict cross-sectional representations of anembodiment of a temperature limited heater with a ferromagnetic outerconductor.

FIGS. 52, 53, and 54 depict cross-sectional representations of anembodiment of a temperature limited heater with an outer conductor.

FIGS. 55, 56, 57, and 58 depict cross-sectional representations of anembodiment of a temperature limited heater.

FIGS. 59, 60, and 61 depict cross-sectional representations of anembodiment of a temperature limited heater with an overburden sectionand a heating section.

FIGS. 62A and 62B depict cross-sectional representations of anembodiment of a temperature limited heater.

FIGS. 63A and 63B depict cross-sectional representations of anembodiment of a temperature limited heater.

FIGS. 64A and 64B depict cross-sectional representations of anembodiment of a temperature limited heater.

FIGS. 65A and 65B depict cross-sectional representations of anembodiment of a temperature limited heater.

FIGS. 66A and 66B depict cross-sectional representations of anembodiment of a temperature limited heater.

FIGS. 67A and 67B depict cross-sectional representations of anembodiment of a temperature limited heater.

FIG. 68 depicts an embodiment of a coupled section of a compositeelectrical conductor.

FIG. 69 depicts an end view of an embodiment of a coupled section of acomposite electrical conductor.

FIG. 70 depicts an embodiment for coupling together sections of acomposite electrical conductor.

FIG. 71 depicts a cross-sectional representation of an embodiment of acomposite conductor with a support member.

FIG. 72 depicts a cross-sectional representation of an embodiment of acomposite conductor with a support member separating the conductors.

FIG. 73 depicts a cross-sectional representation of an embodiment of acomposite conductor surrounding a support member.

FIG. 74 depicts a cross-sectional representation of an embodiment of acomposite conductor surrounding a conduit support member.

FIG. 75 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit heat source.

FIG. 76 depicts a cross-sectional representation of an embodiment of aremovable conductor-in-conduit heat source.

FIG. 77 depicts an embodiment of a sliding connector.

FIG. 78A depicts an embodiment of contacting sections for aconductor-in-conduit heater.

FIG. 78B depicts an aerial view of the upper contact section of theconductor-in-conduit heater in FIG. 78A.

FIG. 79 depicts an embodiment of a fiber optic cable sleeve in aconductor-in-conduit heater.

FIG. 80 depicts an embodiment of a conductor-in-conduit temperaturelimited heater.

FIG. 81A and FIG. 81B depict an embodiment of an insulated conductorheater.

FIG. 82A and FIG. 82B depict an embodiment of an insulated conductorheater.

FIG. 83 depicts an embodiment of an insulated conductor located inside aconduit.

FIG. 84 depicts an embodiment of a temperature limited heater in whichthe support member provides a majority of the heat output below theCurie temperature of the ferromagnetic conductor.

FIGS. 85 and 86 depict embodiments of temperature limited heaters inwhich the jacket provides a majority of the heat output below the Curietemperature of the ferromagnetic conductor.

FIG. 87 depicts a high temperature embodiment of a temperature limitedheater.

FIG. 88 depicts hanging stress versus outside diameter for thetemperature limited heater shown in FIG. 84 with 347H as the supportmember.

FIG. 89 depicts hanging stress versus temperature for several materialsand varying outside diameters of the temperature limited heater.

FIGS. 90, 91, 92, and 93 depict examples of embodiments for temperaturelimited heaters that vary the materials and/or dimensions along thelength of the heaters to provide desired operating properties.

FIGS. 94 and 95 depict examples of embodiments for temperature limitedheaters that vary the diameter and/or materials of the support memberalong the length of the heaters to provide desired operating propertiesand sufficient mechanical properties.

FIGS. 96A and 96B depict cross-sectional representations of anembodiment of a temperature limited heater component used in aninsulated conductor heater.

FIGS. 97A and 97B depict an embodiment for installing heaters in awellbore.

FIG. 97C depicts an embodiment of an insulated conductor with the sheathshorted to the conductors.

FIGS. 98A and 98B depict an embodiment of a three conductor-in-conduitheater.

FIG. 99 depicts an embodiment for coupling together sections of a longtemperature limited heater.

FIG. 100 depicts an embodiment of a shield for orbital welding togethersections of a long temperature limited heater.

FIG. 101 depicts a schematic representation of a shut off circuit for anorbital welding machine.

FIG. 102 depicts an embodiment of a temperature limited heater with alow temperature ferromagnetic outer conductor.

FIG. 103 depicts an embodiment of a temperature limitedconductor-in-conduit heater.

FIG. 104 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater.

FIG. 105 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater.

FIG. 106 depicts a cross-sectional view of an embodiment of aconductor-in-conduit temperature limited heater.

FIG. 107 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater with an insulatedconductor.

FIG. 108 depicts a cross-sectional representation of an embodiment of aninsulated conductor-in-conduit temperature limited heater.

FIG. 109 depicts a cross-sectional representation of an embodiment of aninsulated conductor-in-conduit temperature limited heater.

FIG. 110 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater with an insulatedconductor.

FIGS. 111 and 112 depict cross-sectional views of an embodiment of atemperature limited heater that includes an insulated conductor.

FIGS. 113 and 114 depict cross-sectional views of an embodiment of atemperature limited heater that includes an insulated conductor.

FIG. 115 depicts a schematic of an embodiment of a temperature limitedheater.

FIG. 116 depicts an embodiment of an “S” bend in a heater.

FIG. 117 depicts an embodiment of a three-phase temperature limitedheater, with a portion shown in cross section.

FIG. 118 depicts an embodiment of a three-phase temperature limitedheater, with a portion shown in cross section.

FIG. 119 depicts an embodiment of temperature limited heaters coupledtogether in a three-phase configuration.

FIG. 120 depicts an embodiment of two temperature limited heaterscoupled together in a single contacting section.

FIG. 121 depicts an embodiment of two temperature limited heaters withlegs coupled in a contacting section.

FIG. 122 depicts an embodiment of two temperature limited heaters withlegs coupled in a contacting section with contact solution.

FIG. 123 depicts an embodiment of two temperature limited heaters withlegs coupled without a contactor in a contacting section.

FIG. 124 depicts an embodiment of three heaters coupled in a three-phaseconfiguration.

FIG. 125 depicts a side view representation of an embodiment of asubstantially u-shaped three-phase heater.

FIG. 126 depicts a top view representation of an embodiment of aplurality of triads of three-phase heaters in a formation.

FIG. 127 depicts a top view representation of the embodiment depicted inFIG. 126 with production wells.

FIG. 128 depicts a top view representation of an embodiment of aplurality of triads of three-phase heaters in a hexagonal pattern.

FIG. 129 depicts a top view representation of an embodiment of a hexagonfrom FIG. 128.

FIG. 130 depicts an embodiment of triads of heaters coupled to ahorizontal bus bar.

FIG. 131 depicts cumulative gas production and cumulative oil productionversus time found from a STARS simulation using the heaters and heaterpattern depicted in FIGS. 124 and 126.

FIGS. 132 and 133 depict embodiments for coupling contacting elements ofthree legs of a heater.

FIG. 134 depicts an embodiment of a container with an initiator formelting the coupling material.

FIG. 135 depicts an embodiment of a container for coupling contactingelements with bulbs on the contacting elements.

FIG. 136 depicts an alternative embodiment for a container.

FIG. 137 depicts an alternative embodiment for coupling contactingelements of three legs of a heater.

FIG. 138 depicts a side view representation of an embodiment forcoupling contacting elements using temperature limited heating elements.

FIG. 139 depicts a side view representation of an alternative embodimentfor coupling contacting elements using temperature limited heatingelements.

FIG. 140 depicts side view representation of another alternativeembodiment for coupling contacting elements using temperature limitedheating elements.

FIG. 141 depicts a side view representation of an alternative embodimentfor coupling contacting elements of three legs of a heater.

FIG. 142 depicts a top view representation of the alternative embodimentfor coupling contacting elements of three legs of a heater depicted inFIG. 141.

FIG. 143 depicts an embodiment of a contacting element with a brushcontactor.

FIG. 144 depicts an embodiment for coupling contacting elements withbrush contactors.

FIG. 145 depicts a side-view representation of an embodiment ofsubstantially u-shaped heaters.

FIG. 146 depicts a representational top view of an embodiment of asurface pattern of heaters depicted in FIG. 145.

FIG. 147 depicts a cross-sectional representation of substantiallyu-shaped heaters in a hydrocarbon layer.

FIG. 148 depicts a side view representation of an embodiment ofsubstantially vertical heaters coupled to a substantially horizontalwellbore.

FIG. 149 depicts an embodiment of a substantially u-shaped heater thatelectrically isolates itself from the formation.

FIGS. 150A and 150B depict an embodiment for using substantiallyu-shaped wellbores to time sequence heat two layers in a hydrocarboncontaining formation.

FIG. 151 depicts an embodiment of a temperature limited heater withcurrent return through the formation.

FIG. 152 depicts a representation of an embodiment of a three-phasetemperature limited heater with current connection through theformation.

FIG. 153 depicts an aerial view of the embodiment shown in FIG. 152.

FIG. 154 depicts an embodiment of three temperature limited heaterselectrically coupled to a horizontal wellbore in the formation.

FIG. 155 depicts a representation of an embodiment of a three-phasetemperature limited heater with a common current connection through theformation.

FIG. 156 depicts a side view representation of an embodiment forproducing mobilized fluids from a tar sands formation.

FIG. 157 depicts a representation of an embodiment for producinghydrocarbons from a tar sands formation.

FIG. 158 depicts an embodiment for heating and producing from aformation with a temperature limited heater in a production wellbore.

FIG. 159 depicts an embodiment for heating and producing from aformation with a temperature limited heater and a production wellbore.

FIG. 160 depicts an embodiment of a heating/production assembly that maybe located in a wellbore for gas lifting.

FIG. 161 depicts an embodiment of a heating/production assembly that maybe located in a wellbore for gas lifting.

FIG. 162 depicts another embodiment of a heating/production assemblythat may be located in a wellbore for gas lifting.

FIG. 163 depicts an embodiment of a production conduit and a heater.

FIG. 164 depicts an embodiment for treating a formation.

FIG. 165 depicts an embodiment of a heater well with selective heating.

FIG. 166 depicts electrical resistance versus temperature at variousapplied electrical currents for a 446 stainless steel rod.

FIG. 167 shows resistance profiles as a function of temperature atvarious applied electrical currents for a copper rod contained in aconduit of Sumitomo HCM12A.

FIG. 168 depicts electrical resistance versus temperature at variousapplied electrical currents for a temperature limited heater.

FIG. 169 depicts raw data for a temperature limited heater.

FIG. 170 depicts electrical resistance versus temperature at variousapplied electrical currents for a temperature limited heater.

FIG. 171 depicts power versus temperature at various applied electricalcurrents for a temperature limited heater.

FIG. 172 depicts electrical resistance versus temperature at variousapplied electrical currents for a temperature limited heater.

FIG. 173 depicts data of electrical resistance versus temperature for asolid 2.54 cm diameter, 1.8 m long 410 stainless steel rod at variousapplied electrical currents.

FIG. 174 depicts data of electrical resistance versus temperature for acomposite 1.9 cm, 1.8 m long alloy 42-6 rod with a copper core (the rodhas an outside diameter to copper diameter ratio of 2:1) at variousapplied electrical currents.

FIG. 175 depicts data of power output versus temperature for a composite1.9 cm, 1.8 m long alloy 42-6 rod with a copper core (the rod has anoutside diameter to copper diameter ratio of 2:1) at various appliedelectrical currents.

FIG. 176 depicts data of electrical resistance versus temperature for acomposite 0.75″ diameter, 6 foot long Alloy 52 rod with a 0.375″diameter copper core at various applied electrical currents.

FIG. 177 depicts data of power output versus temperature for a composite1.75″ diameter, 6 foot long Alloy 52 rod with a 0.375″ diameter coppercore at various applied electrical currents.

FIG. 178 depicts data for values of skin depth versus temperature for asolid 2.54 cm diameter, 1.8 m long 410 stainless steel rod at variousapplied AC electrical currents.

FIG. 179 depicts temperature versus time for a temperature limitedheater.

FIG. 180 depicts temperature versus log time data for a 2.5 cm solid 410stainless steel rod and a 2.5 cm solid 304 stainless steel rod.

FIG. 181 depicts experimentally measured resistance versus temperatureat several currents for a temperature limited heater with a copper core,a carbon steel ferromagnetic conductor, and a stainless steel 347Hstainless steel support member.

FIG. 182 depicts experimentally measured resistance versus temperatureat several currents for a temperature limited heater with a copper core,an iron-cobalt ferromagnetic conductor, and a stainless steel 347Hstainless steel support member.

FIG. 183 depicts experimentally measured power factor versus temperatureat two AC currents for a temperature limited heater with a copper core,a carbon steel ferromagnetic conductor, and a 347H stainless steelsupport member.

FIG. 184 depicts experimentally measured turndown ratio versus maximumpower delivered for a temperature limited heater with a copper core, acarbon steel ferromagnetic conductor, and a 347H stainless steel supportmember.

FIG. 185 depicts examples of relative magnetic permeability versusmagnetic field for both the found correlations and raw data for carbonsteel.

FIG. 186 shows the resulting plots of skin depth versus magnetic fieldfor four temperatures and 400 A current.

FIG. 187 shows a comparison between the experimental and numerical(calculated) results for currents of 300 A, 400 A, and 500 A.

FIG. 188 shows the AC resistance per foot of the heater element as afunction of skin depth at 1100° F. calculated from the theoreticalmodel.

FIG. 189 depicts the power generated per unit length in each heatercomponent versus skin depth for a temperature limited heater.

FIGS. 190 A-C compare the results of theoretical calculations withexperimental data for resistance versus temperature in a temperaturelimited heater.

FIG. 191 displays temperature of the center conductor of aconductor-in-conduit heater as a function of formation depth for a Curietemperature heater with a turndown ratio of 2:1.

FIG. 192 displays heater heat flux through a formation for a turndownratio of 2:1 along with the oil shale richness profile.

FIG. 193 displays heater temperature as a function of formation depthfor a turndown ratio of 3:1.

FIG. 194 displays heater heat flux through a formation for a turndownratio of 3:1 along with the oil shale richness profile.

FIG. 195 displays heater temperature as a function of formation depthfor a turndown ratio of 4:1.

FIG. 196 depicts heater temperature versus depth for heaters used in asimulation for heating oil shale.

FIG. 197 depicts heater heat flux versus time for heaters used in asimulation for heating oil shale.

FIG. 198 depicts accumulated heat input versus time in a simulation forheating oil shale.

FIG. 199 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for iron alloy TC3.

FIG. 200 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for iron alloy FM-4.

FIG. 201 depicts the Curie temperature and phase transformationtemperature range for several iron alloys.

FIG. 202 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt and 0.4% by weight manganese.

FIG. 203 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt, 0.4% by weight manganese, and 0.01% carbon.

FIG. 204 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt, 0.4% by weight manganese, and 0.085%carbon.

FIG. 205 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt, 0.4% by weight manganese, 0.085% carbon,and 0.4% titanium.

FIG. 206 shows heater rod temperature as a function of the powergenerated within a rod.

FIG. 207 shows heater rod temperature as a function of the powergenerated within a rod.

FIG. 208 shows heater rod temperature as a function of the powergenerated within a rod.

FIG. 209 shows heater rod temperature as a function of the powergenerated within a rod.

FIG. 210 shows heater rod temperature as a function of the powergenerated within a rod.

FIG. 211 shows heater rod temperature as a function of the powergenerated within a rod.

FIG. 212 shows heater rod temperature as a function of the powergenerated within a rod.

FIG. 213 shows heater rod temperature as a function of the powergenerated within a rod.

FIG. 214 shows a plot of center heater rod temperature versus conduittemperature for various heater powers with air or helium in the annulus.

FIG. 215 shows a plot of center heater rod temperature versus conduittemperature for various heater powers with air or helium in the annulus.

FIG. 216 depicts spark gap breakdown voltages versus pressure atdifferent temperatures for a conductor-in-conduit heater with air in theannulus.

FIG. 217 depicts spark gap breakdown voltages versus pressure atdifferent temperatures for a conductor-in-conduit heater with helium inthe annulus.

FIG. 218 depicts data of leakage current measurements versus voltage foralumina and silicon nitride centralizers at selected temperatures.

FIG. 219 depicts leakage current measurements versus temperature for twodifferent types of silicon nitride.

FIG. 220 depicts projected corrosion rates over a one-year period forseveral metals in a sulfidation atmosphere.

FIG. 221 depicts projected corrosion rates over a one-year period for410 stainless steel and 410 stainless steel containing various amountsof cobalt in a sulfidation atmosphere.

FIG. 222 depicts an example of richness of an oil shale formation(gal/ton) versus depth (ft).

FIG. 223 depicts resistance per foot (mΩ/ft) versus temperature (° F.)profile of a first example of a heater.

FIG. 224 depicts average temperature in the formation (° F.) versus time(days) as determined by the simulation for the first example.

FIG. 225 depicts resistance per foot (mΩ/ft) versus temperature (° F.)for the second heater example.

FIG. 226 depicts average temperature in the formation (° F.) versus time(days) as determined by the simulation for the second example.

FIG. 227 depicts net heater energy input (Btu) versus time (days) forthe second example.

FIG. 228 depicts power injection per foot (W/ft) versus time (days) forthe second example.

FIG. 229 depicts resistance per foot (mΩ/ft) versus temperature (° F.)for the third heater example.

FIG. 230 depicts average temperature in the formation (° F.) versus time(days) as determined by the simulation for the third example.

FIG. 231 depicts cumulative energy injection (Btu) versus time (days)for each of the three heater examples.

FIG. 232 depicts average temperature (° F.) versus time (days) for thethird heater example with a 30 foot spacing between heaters in theformation as determined by the simulation.

FIG. 233 depicts average temperature (° F.) versus time (days) for thefourth heater example using the heater configuration and patterndepicted in FIGS. 124 and 126 as determined by the simulation.

FIG. 234 depicts a schematic representation of an embodiment of aheating system with a downhole gas turbine.

FIG. 235 depicts a schematic representation of a closed loop circulationsystem for heating a portion of a formation.

FIG. 236 depicts a plan view of wellbore entries and exits from aportion of a formation to be heated using a closed loop circulationsystem.

FIG. 237 depicts a side view representation of an embodiment of a systemfor heating the formation that can use a closed loop circulation systemand/or electrical heating.

FIG. 238 depicts an embodiment of a windmill for generating electricityfor subsurface heaters.

FIG. 239 depicts an embodiment for solution mining a formation.

FIG. 240 depicts an embodiment of a formation with nahcolite layers inthe formation before solution mining nahcolite from the formation.

FIG. 241 depicts the formation of FIG. 240 after the nahcolite has beensolution mined.

FIG. 242 depicts an embodiment of two injection wells interconnected bya zone that has been solution mined to remove nahcolite from the zone.

FIG. 243 depicts an embodiment for heating a formation with dawsonite inthe formation.

FIG. 244 depicts an embodiment of treating a hydrocarbon containingformation with a combustion front.

FIG. 245 depicts an embodiment of cross-sectional view of treating ahydrocarbon containing formation with a combustion front.

While the invention is susceptible to various modifications andalternative forms, specific embodiments thereof are shown by way ofexample in the drawings and may herein be described in detail. Thedrawings may not be to scale. It should be understood, however, that thedrawings and detailed description thereto are not intended to limit theinvention to the particular form disclosed, but on the contrary, theintention is to cover all modifications, equivalents and alternativesfalling within the spirit and scope of the present invention as definedby the appended claims.

DETAILED DESCRIPTION

The following description generally relates to systems and methods fortreating hydrocarbons in the formations. Such formations may be treatedto yield hydrocarbon products, hydrogen, and other products.

“Hydrocarbons” are generally defined as molecules formed primarily bycarbon and hydrogen atoms. Hydrocarbons may also include other elementssuch as, but not limited to, halogens, metallic elements, nitrogen,oxygen, and/or sulfur. Hydrocarbons may be, but are not limited to,kerogen, bitumen, pyrobitumen, oils, natural mineral waxes, andasphaltites. Hydrocarbons may be located in or adjacent to mineralmatrices in the earth. Matrices may include, but are not limited to,sedimentary rock, sands, silicilytes, carbonates, diatomites, and otherporous media. “Hydrocarbon fluids” are fluids that include hydrocarbons.Hydrocarbon fluids may include, entrain, or be entrained innon-hydrocarbon fluids such as hydrogen, nitrogen, carbon monoxide,carbon dioxide, hydrogen sulfide, water, and ammonia.

A “formation” includes one or more hydrocarbon containing layers, one ormore non-hydrocarbon layers, an overburden, and/or an underburden. The“overburden” and/or the “underburden” include one or more differenttypes of impermeable materials. For example, overburden and/orunderburden may include rock, shale, mudstone, or wet/tight carbonate.In some embodiments of in situ conversion processes, the overburdenand/or the underburden may include a hydrocarbon containing layer orhydrocarbon containing layers that are relatively impermeable and arenot subjected to temperatures during in situ conversion processing thatresult in significant characteristic changes of the hydrocarboncontaining layers of the overburden and/or the underburden. For example,the underburden may contain shale or mudstone, but the underburden isnot allowed to heat to pyrolysis temperatures during the in situconversion process. In some cases, the overburden and/or the underburdenmay be somewhat permeable.

“Kerogen” is a solid, insoluble hydrocarbon that has been converted bynatural degradation and that principally contains carbon, hydrogen,nitrogen, oxygen, and sulfur. Coal and oil shale are typical examples ofmaterials that contain kerogen. “Bitumen” is a non-crystalline solid orviscous hydrocarbon material that is substantially soluble in carbondisulfide. “Oil” is a fluid containing a mixture of condensablehydrocarbons.

“Formation fluids” refer to fluids present in a formation and mayinclude pyrolyzation fluid, synthesis gas, mobilized hydrocarbon, andwater (steam). Formation fluids may include hydrocarbon fluids as wellas non-hydrocarbon fluids. The term “mobilized fluid” refers to fluidsin a hydrocarbon containing formation that are able to flow as a resultof thermal treatment of the formation. “Produced fluids” refer to fluidsremoved from the formation.

“Thermally conductive fluid” includes fluid that has a higher thermalconductivity than air at standard temperature and pressure (STP) (0° C.and 101.325 kPa).

“Carbon number” refers to the number of carbon atoms in a molecule. Ahydrocarbon fluid may include various hydrocarbons with different carbonnumbers. The hydrocarbon fluid may be described by a carbon numberdistribution. Carbon numbers and/or carbon number distributions may bedetermined by true boiling point distribution and/or gas-liquidchromatography.

A “heat source” is any system for providing heat to at least a portionof a formation substantially by conductive and/or radiative heattransfer. For example, a heat source may include electric heaters suchas an insulated conductor, an elongated member, and/or a conductordisposed in a conduit. A heat source may also include systems thatgenerate heat by burning a fuel external to or in a formation. Thesystems may be surface burners, downhole gas burners, flamelessdistributed combustors, and natural distributed combustors. In someembodiments, heat provided to or generated in one or more heat sourcesmay be supplied by other sources of energy. The other sources of energymay directly heat a formation, or the energy may be applied to atransfer medium that directly or indirectly heats the formation. It isto be understood that one or more heat sources that are applying heat toa formation may use different sources of energy. Thus, for example, fora given formation some heat sources may supply heat from electricresistance heaters, some heat sources may provide heat from combustion,and some heat sources may provide heat from one or more other energysources (for example, chemical reactions, solar energy, wind energy,biomass, or other sources of renewable energy). A chemical reaction mayinclude an exothermic reaction (for example, an oxidation reaction). Aheat source may also include a heater that provides heat to a zoneproximate and/or surrounding a heating location such as a heater well.

A “heater” is any system or heat source for generating heat in a well ora near wellbore region. Heaters may be, but are not limited to, electricheaters, burners, combustors that react with material in or producedfrom a formation, and/or combinations thereof.

An “in situ conversion process” refers to a process of heating ahydrocarbon containing formation from heat sources to raise thetemperature of at least a portion of the formation above a pyrolysistemperature so that pyrolyzation fluid is produced in the formation.

“Insulated conductor” refers to any elongated material that is able toconduct electricity and that is covered, in whole or in part, by anelectrically insulating material.

An elongated member may be a bare metal heater or an exposed metalheater. “Bare metal” and “exposed metal” refer to metals that do notinclude a layer of electrical insulation, such as mineral insulation,that is designed to provide electrical insulation for the metalthroughout an operating temperature range of the elongated member. Baremetal and exposed metal may encompass a metal that includes a corrosioninhibitor such as a naturally occurring oxidation layer, an appliedoxidation layer, and/or a film. Bare metal and exposed metal includemetals with polymeric or other types of electrical insulation thatcannot retain electrical insulating properties at typical operatingtemperature of the elongated member. Such material may be placed on themetal and may be thermally degraded during use of the heater.

“Temperature limited heater” generally refers to a heater that regulatesheat output (for example, reduces heat output) above a specifiedtemperature without the use of external controls such as temperaturecontrollers, power regulators, rectifiers, or other devices. Temperaturelimited heaters may be AC (alternating current) or modulated (forexample, “chopped”) DC (direct current) powered electrical resistanceheaters.

“Curie temperature” is the temperature above which a ferromagneticmaterial loses all of its ferromagnetic properties. In addition tolosing all of its ferromagnetic properties above the Curie temperature,the ferromagnetic material begins to lose its ferromagnetic propertieswhen an increasing electrical current is passed through theferromagnetic material.

“Time-varying current” refers to electrical current that produces skineffect electricity flow in a ferromagnetic conductor and has a magnitudethat varies with time. Time-varying current includes both alternatingcurrent (AC) and modulated direct current (DC).

“Alternating current (AC)” refers to a time-varying current thatreverses direction substantially sinusoidally. AC produces skin effectelectricity flow in a ferromagnetic conductor.

“Modulated direct current (DC)” refers to any substantiallynon-sinusoidal time-varying current that produces skin effectelectricity flow in a ferromagnetic conductor.

“Turndown ratio” for the temperature limited heater is the ratio of thehighest AC or modulated DC resistance below the Curie temperature to thelowest resistance above the Curie temperature for a given current.

In the context of reduced heat output heating systems, apparatus, andmethods, the term “automatically” means such systems, apparatus, andmethods function in a certain way without the use of external control(for example, external controllers such as a controller with atemperature sensor and a feedback loop, PID controller, or predictivecontroller).

“Nitride” refers to a compound of nitrogen and one or more otherelements of the Periodic Table. Nitrides include, but are not limitedto, silicon nitride, boron nitride, or alumina nitride.

The term “wellbore” refers to a hole in a formation made by drilling orinsertion of a conduit into the formation. A wellbore may have asubstantially circular cross section, or another cross-sectional shape.As used herein, the terms “well” and “opening,” when referring to anopening in the formation may be used interchangeably with the term“wellbore.”

A “u-shaped wellbore” refers to a wellbore that extends from a firstopening in the formation, through at least a portion of the formation,and out through a second opening in the formation. In this context, thewellbore may be only roughly in the shape of a “v” or “u”, with theunderstanding that the “legs” of the “u” do not need to be parallel toeach other, or perpendicular to the “bottom” of the “u” for the wellboreto be considered “u-shaped”.

“Triad” refers to a group of three items (for example, heaters,wellbores, or other objects) coupled together.

“Orifices” refer to openings, such as openings in conduits, having awide variety of sizes and cross-sectional shapes including, but notlimited to, circles, ovals, squares, rectangles, triangles, slits, orother regular or irregular shapes.

“Pyrolysis” is the breaking of chemical bonds due to the application ofheat. For example, pyrolysis may include transforming a compound intoone or more other substances by heat alone. Heat may be transferred to asection of the formation to cause pyrolysis.

“Pyrolyzation fluids” or “pyrolysis products” refers to fluid producedsubstantially during pyrolysis of hydrocarbons. Fluid produced bypyrolysis reactions may mix with other fluids in a formation. Themixture would be considered pyrolyzation fluid or pyrolyzation product.As used herein, “pyrolysis zone” refers to a volume of a formation (forexample, a relatively permeable formation such as a tar sands formation)that is reacted or reacting to form a pyrolyzation fluid.

“Cracking” refers to a process involving decomposition and molecularrecombination of organic compounds to produce a greater number ofmolecules than were initially present. In cracking, a series ofreactions take place accompanied by a transfer of hydrogen atoms betweenmolecules. For example, naphtha may undergo a thermal cracking reactionto form ethene and H₂.

“Clogging” refers to impeding and/or inhibiting flow of one or morecompositions through a process vessel or a conduit.

“Superposition of heat” refers to providing heat from two or more heatsources to a selected section of a formation such that the temperatureof the formation at least at one location between the heat sources isinfluenced by the heat sources.

“Thermal conductivity” is a property of a material that describes therate at which heat flows, in steady state, between two surfaces of thematerial for a given temperature difference between the two surfaces.

“Fluid pressure” is a pressure generated by a fluid in a formation.“Lithostatic pressure” (sometimes referred to as “lithostatic stress”)is a pressure in a formation equal to a weight per unit area of anoverlying rock mass. “Hydrostatic pressure” is a pressure in a formationexerted by a column of water.

“Condensable hydrocarbons” are hydrocarbons that condense at 25° C. andone atmosphere absolute pressure. Condensable hydrocarbons may include amixture of hydrocarbons having carbon numbers greater than 4.“Non-condensable hydrocarbons” are hydrocarbons that do not condense at25° C. and one atmosphere absolute pressure. Non-condensablehydrocarbons may include hydrocarbons having carbon numbers less than 5.

“Olefins” are molecules that include unsaturated hydrocarbons having oneor more non-aromatic carbon-carbon double bonds.

“Naphtha” refers to hydrocarbon components with a boiling rangedistribution between 38° C. and 200° C. at 0.101 MPa. Naphtha content isdetermined by American Standard Testing and Materials (ASTM) MethodD5307.

“Kerosene” refers to hydrocarbons with a boiling range distributionbetween 204° C. and 260° C. at 0.101 MPa. Kerosene content is determinedby ASTM Method D2887.

“Diesel” refers to hydrocarbons with a boiling range distributionbetween 260° C. and 343° C. (500-650° F.) at 0.101 MPa. Diesel contentis determined by ASTM Method D2887.

“VGO” or “vacuum gas oil” refers to hydrocarbons with a boiling rangedistribution between 343° C. and 538° C. at 0.101 MPa. VGO content isdetermined by ASTM Method D5307.

“API gravity” refers to API gravity at 15.5° C. (60° F.). API gravity isas determined by ASTM Method D6822.

“Synthesis gas” is a mixture including hydrogen and carbon monoxide.Additional components of synthesis gas may include water, carbondioxide, nitrogen, methane, and other gases. Synthesis gas may begenerated by a variety of processes and feedstocks. Synthesis gas may beused for synthesizing a wide range of compounds.

“Subsidence” is a downward movement of a portion of a formation relativeto an initial elevation of the surface.

“Thickness” of a layer refers to the thickness of a cross section of thelayer, wherein the cross section is normal to a face of the layer.

“Coring” is a process that generally includes drilling a hole into aformation and removing a substantially solid mass of the formation fromthe hole.

“Enriched air” refers to air having a larger mole fraction of oxygenthan air in the atmosphere. Air is typically enriched to increasecombustion-supporting ability of the air.

“Rich layers” in a hydrocarbon containing formation are relatively thinlayers (typically about 0.2 m to about 0.5 m thick). Rich layersgenerally have a richness of about 0.150 L/kg or greater. Some richlayers have a richness of about 0.170 L/kg or greater, of about 0.190L/kg or greater, or of about 0.210 L/kg or greater. Lean layers of theformation have a richness of about 0.100 L/kg or less and are generallythicker than rich layers. The richness and locations of layers aredetermined, for example, by coring and subsequent Fischer assay of thecore, density or neutron logging, or other logging methods. Rich layershave a lower initial thermal conductivity than other layers of theformation. Typically, rich layers have a thermal conductivity 1.5 timesto 3 times lower than the thermal conductivity of lean layers. Inaddition, rich layers have a higher thermal expansion coefficient thanlean layers of the formation.

“Heavy hydrocarbons” are viscous hydrocarbon fluids. Heavy hydrocarbonsmay include highly viscous hydrocarbon fluids such as heavy oil, tar,and/or asphalt. Heavy hydrocarbons may include carbon and hydrogen, aswell as smaller concentrations of sulfur, oxygen, and nitrogen.Additional elements may also be present in heavy hydrocarbons in traceamounts. Heavy hydrocarbons may be classified by API gravity. Heavyhydrocarbons generally have an API gravity below about 20°. Heavy oil,for example, generally has an API gravity of about 10-20°, whereas targenerally has an API gravity below about 10°. The viscosity of heavyhydrocarbons is generally greater than about 100 centipoise at 15° C.Heavy hydrocarbons may include aromatics or other complex ringhydrocarbons.

Heavy hydrocarbons may be found in a relatively permeable formation. Therelatively permeable formation may include heavy hydrocarbons entrainedin, for example, sand or carbonate. “Relatively permeable” is defined,with respect to formations or portions thereof, as an averagepermeability of 10 millidarcy or more (for example, 10 or 100millidarcy). “Relatively low permeability” is defined, with respect toformations or portions thereof, as an average permeability of less thanabout 10 millidarcy. One darcy is equal to about 0.99 squaremicrometers. An impermeable layer generally has a permeability of lessthan about 0.1 millidarcy.

“Tar” is a viscous hydrocarbon that generally has a viscosity greaterthan about 10,000 centipoise at 15° C. The specific gravity of targenerally is greater than 1.000. Tar may have an API gravity less than10°.

A “tar sands formation” is a formation in which hydrocarbons arepredominantly present in the form of heavy hydrocarbons and/or tarentrained in a mineral grain framework or other host lithology (forexample, sand or carbonate).

In some cases, a portion or all of a hydrocarbon portion of a relativelypermeable formation may be predominantly heavy hydrocarbons and/or tarwith no supporting mineral grain framework and only floating (or no)mineral matter (for example, asphalt lakes).

Certain types of formations that include heavy hydrocarbons may also be,but are not limited to, natural mineral waxes, or natural asphaltites.“Natural mineral waxes” typically occur in substantially tubular veinsthat may be several meters wide, several kilometers long, and hundredsof meters deep. “Natural asphaltites” include solid hydrocarbons of anaromatic composition and typically occur in large veins. In siturecovery of hydrocarbons from formations such as natural mineral waxesand natural asphaltites may include melting to form liquid hydrocarbonsand/or solution mining of hydrocarbons from the formations.

“Upgrade” refers to increasing the quality of hydrocarbons. For example,upgrading heavy hydrocarbons may result in an increase in the APIgravity of the heavy hydrocarbons.

“Thermal fracture” refers to fractures created in a formation caused byexpansion or contraction of a formation and/or fluids in the formation,which is in turn caused by increasing/decreasing the temperature of theformation and/or fluids in the formation, and/or byincreasing/decreasing a pressure of fluids in the formation due toheating.

“Periodic Table” refers to the Periodic Table as specified by theInternational Union of Pure and Applied Chemistry (IUPAC), November2003.

“Column X metal” or “Column X metals” refer to one or more metals ofColumn X of the Periodic Table and/or one or more compounds of one ormore metals of Column X of the Periodic Table, in which X corresponds toa column number (for example, I-12) of the Periodic Table. For example,“Column 6 metals” refer to metals from Column 6 of the Periodic Tableand/or compounds of one or more metals from Column 6 of the PeriodicTable.

“Column X element” or “Column X elements” refer to one or more elementsof Column X of the Periodic Table, and/or one or more compounds of oneor more elements of Column X of the Periodic Table, in which Xcorresponds to a column number (for example, 13-18) of the PeriodicTable. For example, “Column 15 elements” refer to elements from Column15 of the Periodic Table and/or compounds of one or more elements fromColumn 15 of the Periodic Table.

In the scope of this application, weight of a metal from the PeriodicTable, weight of a compound of a metal from the Periodic Table, weightof an element from the Periodic Table, or weight of a compound of anelement from the Periodic Table is calculated as the weight of metal orthe weight of element. For example, if 0.1 grams of MoO₃ is used pergram of catalyst, the calculated weight of the molybdenum metal in thecatalyst is 0.067 grams per gram of catalyst.

Hydrocarbons in formations may be treated in various ways to producemany different products. In certain embodiments, hydrocarbons informations are treated in stages. FIG. 1 depicts an illustration ofstages of heating the hydrocarbon containing formation. FIG. 1 alsodepicts an example of yield (“Y”) in barrels of oil equiva lent per ton(y axis) of formation fluids from the formation versus temperature (“T”)of the heated formation in degrees Celsius (x axis).

Desorption of methane and vaporization of water occurs during stage 1heating. Heating of the formation through stage 1 may be performed asquickly as possible. For example, when the hydrocarbon containingformation is initially heated, hydrocarbons in the formation desorbadsorbed methane. The desorbed methane may be produced from theformation. If the hydrocarbon containing formation is heated further,water in the hydrocarbon containing formation is vaporized. Water mayoccupy, in some hydrocarbon containing formations, between 10% and 50%of the pore volume in the formation. In other formations, water occupieslarger or smaller portions of the pore volume. Water typically isvaporized in a formation between 160° C. and 285° C. at pressures of 600kPa absolute to 7000 kPa absolute. In some embodiments, the vaporizedwater produces wettability changes in the formation and/or increasedformation pressure. The wettability changes and/or increased pressuremay affect pyrolysis reactions or other reactions in the formation. Incertain embodiments, the vaporized water is produced from the formation.In other embodiments, the vaporized water is used for steam extractionand/or distillation in the formation or outside the formation. Removingthe water from and increasing the pore volume in the formation increasesthe storage space for hydrocarbons in the pore volume.

In certain embodiments, after stage 1 heating, the formation is heatedfurther, such that a temperature in the formation reaches (at least) aninitial pyrolyzation temperature (such as a temperature at the lower endof the temperature range shown as stage 2). Hydrocarbons in theformation may be pyrolyzed throughout stage 2. A pyrolysis temperaturerange varies depending on the types of hydrocarbons in the formation.The pyrolysis temperature range may include temperatures between 250° C.and 900° C. The pyrolysis temperature range for producing desiredproducts may extend through only a portion of the total pyrolysistemperature range. In some embodiments, the pyrolysis temperature rangefor producing desired products may include temperatures between 250° C.and 400° C. or temperatures between 270° C. and 350° C. If a temperatureof hydrocarbons in the formation is slowly raised through thetemperature range from 250° C. to 400° C., production of pyrolysisproducts may be substantially complete when the temperature approaches400° C. Average temperature of the hydrocarbons may be raised at a rateof less than 5° C. per day, less than 2° C. per day, less than 1° C. perday, or less than 0.5° C. per day through the pyrolysis temperaturerange for producing desired products. Heating the hydrocarbon containingformation with a plurality of heat sources may establish thermalgradients around the heat sources that slowly raise the temperature ofhydrocarbons in the formation through the pyrolysis temperature range.

The rate of temperature increase through the pyrolysis temperature rangefor desired products may affect the quality and quantity of theformation fluids produced from the hydrocarbon containing formation.Raising the temperature slowly through the pyrolysis temperature rangefor desired products may inhibit mobilization of large chain moleculesin the formation. Raising the temperature slowly through the pyrolysistemperature range for desired products may limit reactions betweenmobilized hydrocarbons that produce undesired products. Slowly raisingthe temperature of the formation through the pyrolysis temperature rangefor desired products may allow for the production of high quality, highAPI gravity hydrocarbons from the formation. Slowly raising thetemperature of the formation through the pyrolysis temperature range fordesired products may allow for the removal of a large amount of thehydrocarbons present in the formation as hydrocarbon product.

In some in situ conversion embodiments, a portion of the formation isheated to a desired temperature instead of slowly heating thetemperature through a temperature range. In some embodiments, thedesired temperature is 300° C., 325° C., or 350° C. Other temperaturesmay be selected as the desired temperature. Superposition of heat fromheat sources allows the desired temperature to be relatively quickly andefficiently established in the formation. Energy input into theformation from the heat sources may be adjusted to maintain thetemperature in the formation substantially at the desired temperature.The heated portion of the formation is maintained substantially at thedesired temperature until pyrolysis declines such that production ofdesired formation fluids from the formation becomes uneconomical. Partsof the formation that are subjected to pyrolysis may include regionsbrought into a pyrolysis temperature range by heat transfer from onlyone heat source.

In certain embodiments, formation fluids including pyrolyzation fluidsare produced from the formation. As the temperature of the formationincreases, the amount of condensable hydrocarbons in the producedformation fluid may decrease. At high temperatures, the formation mayproduce mostly methane and/or hydrogen. If the hydrocarbon containingformation is heated throughout an entire pyrolysis range, the formationmay produce only small amounts of hydrogen towards an upper limit of thepyrolysis range. After all of the available hydrogen is depleted, aminimal amount of fluid production from the formation will typicallyoccur.

After pyrolysis of hydrocarbons, a large amount of carbon and somehydrogen may still be present in the formation. A significant portion ofcarbon remaining in the formation can be produced from the formation inthe form of synthesis gas. Synthesis gas generation may take placeduring stage 3 heating depicted in FIG. 1. Stage 3 may include heating ahydrocarbon containing formation to a temperature sufficient to allowsynthesis gas generation. For example, synthesis gas may be produced ina temperature range from about 400° C. to about 1200° C., about 500° C.to about 1100° C., or about 550° C. to about 1000° C. The temperature ofthe heated portion of the formation when the synthesis gas generatingfluid is introduced to the formation determines the composition ofsynthesis gas produced in the formation. The generated synthesis gas maybe removed from the formation through a production well or productionwells.

Total energy content of fluids produced from the hydrocarbon containingformation may stay relatively constant throughout pyrolysis andsynthesis gas generation. During pyrolysis at relatively low formationtemperatures, a significant portion of the produced fluid may becondensable hydrocarbons that have a high energy content. At higherpyrolysis temperatures, however, less of the formation fluid may includecondensable hydrocarbons. More non-condensable formation fluids may beproduced from the formation. Energy content per unit volume of theproduced fluid may decline slightly during generation of predominantlynon-condensable formation fluids. During synthesis gas generation,energy content per unit volume of produced synthesis gas declinessignificantly compared to energy content of pyrolyzation fluid. Thevolume of the produced synthesis gas, however, will in many instancesincrease substantially, thereby compensating for the decreased energycontent.

FIG. 2 depicts a schematic view of an embodiment of a portion of the insitu conversion system for treating the hydrocarbon containingformation. The in situ conversion system may include barrier wells 200.Barrier wells are used to form a barrier around a treatment area. Thebarrier inhibits fluid flow into and/or out of the treatment area.Barrier wells include, but are not limited to, dewatering wells, vacuumwells, capture wells, injection wells, grout wells, freeze wells, orcombinations thereof. In some embodiments, barrier wells 200 aredewatering wells. Dewatering wells may remove liquid water and/orinhibit liquid water from entering a portion of the formation to beheated, or to the formation being heated. In the embodiment depicted inFIG. 2, the barrier wells 200 are shown extending only along one side ofheat sources 202, but the barrier wells typically encircle all heatsources 202 used, or to be used, to heat a treatment area of theformation.

Heat sources 202 are placed in at least a portion of the formation. Heatsources 202 may include heaters such as insulated conductors,conductor-in-conduit heaters, surface burners, flameless distributedcombustors, and/or natural distributed combustors. Heat sources 202 mayalso include other types of heaters. Heat sources 202 provide heat to atleast a portion of the formation to heat hydrocarbons in the formation.Energy may be supplied to heat sources 202 through supply lines 204.Supply lines 204 may be structurally different depending on the type ofheat source or heat sources used to heat the formation. Supply lines 204for heat sources may transmit electricity for electric heaters, maytransport fuel for combustors, or may transport heat exchange fluid thatis circulated in the formation.

When the formation is heated, the heat input into the formation maycause expansion of the formation and geomechanical motion. Computersimulations may model formation response to heating. The computersimulations may be used to develop a pattern and time sequence foractivating heat sources in the formation so that geomechanical motion ofthe formation does not adversely affect the functionality of heatsources, production wells, and other equipment in the formation.

Heating the formation may cause an increase in permeability and/orporosity of the formation. Increases in permeability and/or porosity mayresult from a reduction of mass in the formation due to vaporization andremoval of water, removal of hydrocarbons, and/or creation of fractures.Fluid may flow more easily in the heated portion of the formationbecause of the increased permeability and/or porosity of the formation.Fluid in the heated portion of the formation may move a considerabledistance through the formation because of the increased permeabilityand/or porosity. The considerable distance may be over 1000 m dependingon various factors, such as permeability of the formation, properties ofthe fluid, temperature of the formation, and pressure gradient allowingmovement of the fluid. The ability of fluid to travel considerabledistance in the formation allows production wells 206 to be spacedrelatively far apart in the formation.

Production wells 206 are used to remove formation fluid from theformation. In some embodiments, production well 206 includes a heatsource. The heat source in the production well may heat one or moreportions of the formation at or near the production well. In some insitu conversion process embodiments, the amount of heat supplied to theformation from the production well per meter of the production well isless than the amount of heat applied to the formation from a heat sourcethat heats the formation per meter of the heat source. Heat applied tothe formation from the production well may increase formationpermeability adjacent to the production well by vaporizing and removingliquid phase fluid adjacent to the production well and/or by increasingthe permeability of the formation adjacent to the production well byformation of macro and/or micro fractures.

More than one heat source may be positioned in the production well. Aheat source in a lower portion of the production well may be turned offwhen superposition of heat from adjacent heat sources heats theformation sufficiently to counteract benefits provided by heating theformation with the production well. In some embodiments, the heat sourcein an upper portion of the production well may remain on after the heatsource in the lower portion of the production well is deactivated. Theheat source in the upper portion of the well may inhibit condensationand reflux of formation fluid.

In some embodiments, the heat source in production well 206 allows forvapor phase removal of formation fluids from the formation. Providingheating at or through the production well may: (1) inhibit condensationand/or refluxing of production fluid when such production fluid ismoving in the production well proximate the overburden, (2) increaseheat input into the formation, (3) increase production rate from theproduction well as compared to a production well without a heat source,(4) inhibit condensation of high carbon number compounds (C₆ and above)in the production well, and/or (5) increase formation permeability at orproximate the production well.

Subsurface pressure in the formation may correspond to the fluidpressure generated in the formation. As temperatures in the heatedportion of the formation increase, the pressure in the heated portionmay increase as a result of increased fluid generation and vaporizationof water. Controlling rate of fluid removal from the formation may allowfor control of pressure in the formation. Pressure in the formation maybe determined at a number of different locations, such as near or atproduction wells, near or at heat sources, or at monitor wells.

In some hydrocarbon containing formations, production of hydrocarbonsfrom the formation is inhibited until at least some hydrocarbons in theformation have been pyrolyzed. Formation fluid may be produced from theformation when the formation fluid is of a selected quality. In someembodiments, the selected quality includes an API gravity of at leastabout 20°, 30°, or 40°. Inhibiting production until at least somehydrocarbons are pyrolyzed may increase conversion of heavy hydrocarbonsto light hydrocarbons. Inhibiting initial production may minimize theproduction of heavy hydrocarbons from the formation. Production ofsubstantial amounts of heavy hydrocarbons may require expensiveequipment and/or reduce the life of production equipment.

In some hydrocarbon containing formations, hydrocarbons in the formationmay be heated to pyrolysis temperatures before substantial permeabilityhas been generated in the heated portion of the formation. An initiallack of permeability may inhibit the transport of generated fluids toproduction wells 206. During initial heating, fluid pressure in theformation may increase proximate the heat sources 202. The increasedfluid pressure may be released, monitored, altered, and/or controlledthrough one or more heat sources 202. For example, selected heat sources202 or separate pressure relief wells may include pressure relief valvesthat allow for removal of some fluid from the formation.

In some embodiments, pressure generated by expansion of pyrolysis fluidsor other fluids generated in the formation may be allowed to increasealthough an open path to production wells 206 or any other pressure sinkmay not yet exist in the formation. The fluid pressure may be allowed toincrease towards a lithostatic pressure. Fractures in the hydrocarboncontaining formation may form when the fluid approaches the lithostaticpressure. For example, fractures may form from heat sources 202 toproduction wells 206 in the heated portion of the formation. Thegeneration of fractures in the heated portion may relieve some of thepressure in the portion. Pressure in the formation may have to bemaintained below a selected pressure to inhibit unwanted production,fracturing of the overburden or underburden, and/or coking ofhydrocarbons in the formation.

After pyrolysis temperatures are reached and production from theformation is allowed, pressure in the formation may be varied to alterand/or control a composition of formation fluid produced, to control apercentage of condensable fluid as compared to non-condensable fluid inthe formation fluid, and/or to control an API gravity of formation fluidbeing produced. For example, decreasing pressure may result inproduction of a larger condensable fluid component. The condensablefluid component may contain a larger percentage of olefins.

In some in situ conversion process embodiments, pressure in theformation may be maintained high enough to promote production offormation fluid with an API gravity of greater than 20°. Maintainingincreased pressure in the formation may inhibit formation subsidenceduring in situ conversion. Maintaining increased pressure may facilitatevapor phase production of fluids from the formation. Vapor phaseproduction may allow for a reduction in size of collection conduits usedto transport fluids produced from the formation. Maintaining increasedpressure may reduce or eliminate the need to compress formation fluidsat the surface to transport the fluids in collection conduits totreatment facilities.

Maintaining increased pressure in a heated portion of the formation maysurprisingly allow for production of large quantities of hydrocarbons ofincreased quality and of relatively low molecular weight. Pressure maybe maintained so that formation fluid produced has a minimal amount ofcompounds above a selected carbon number. The selected carbon number maybe at most 25, at most 20, at most 12, or at most 8. Some high carbonnumber compounds may be entrained in vapor in the formation and may beremoved from the formation with the vapor. Maintaining increasedpressure in the formation may inhibit entrapment of high carbon numbercompounds and/or multi-ring hydrocarbon compounds in the vapor. Highcarbon number compounds and/or multi-ring hydrocarbon compounds mayremain in a liquid phase in the formation for significant time periods.The significant time periods may provide sufficient time for thecompounds to pyrolyze to form lower carbon number compounds.

Generation of relatively low molecular weight hydrocarbons is believedto be due, in part, to autogenous generation and reaction of hydrogen ina portion of the hydrocarbon containing formation. For example,maintaining an increased pressure may force hydrogen generated duringpyrolysis into the liquid phase within the formation. Heating theportion to a temperature in a pyrolysis temperature range may pyrolyzehydrocarbons in the formation to generate liquid phase pyrolyzationfluids. The generated liquid phase pyrolyzation fluids components mayinclude double bonds and/or radicals. Hydrogen (H₂) in the liquid phasemay reduce double bonds of the generated pyrolyzation fluids, therebyreducing a potential for polymerization or formation of long chaincompounds from the generated pyrolyzation fluids. In addition, H₂ mayalso neutralize radicals in the generated pyrolyzation fluids.Therefore, H₂ in the liquid phase may inhibit the generated pyrolyzationfluids from reacting with each other and/or with other compounds in theformation.

Formation fluid produced from production wells 206 may be transportedthrough collection piping 208 to treatment facilities 210. Formationfluids may also be produced from heat sources 202. For example, fluidmay be produced from heat sources 202 to control pressure in theformation adjacent to the heat sources. Fluid produced from heat sources202 may be transported through tubing or piping to collection piping 208or the produced fluid may be transported through tubing or pipingdirectly to treatment facilities 210. Treatment facilities 210 mayinclude separation units, reaction units, upgrading units, fuel cells,turbines, storage vessels, and/or other systems and units for processingproduced formation fluids. The treatment facilities may formtransportation fuel from at least a portion of the hydrocarbons producedfrom the formation. In some embodiments, the transportation fuel may bejet fuel, such as JP-8.

Formation fluid may be hot when produced from the formation through theproduction wells. Hot formation fluid may be produced during solutionmining processes and/or during in situ conversion processes. In someembodiments, electricity may be generated using the heat of the fluidproduced from the formation. Also, heat recovered from the formationafter the in situ process may be used to generate electricity. Thegenerated electricity may be used to supply power to the in situconversion process. For example, the electricity may be used to powerheaters, or to power a refrigeration system for forming or maintaining alow temperature barrier. Electricity may be generated using a Kalinacycle or a modified Kalina cycle.

FIG. 3 depicts a schematic representation of a Kalina cycle that usesrelatively high pressure aqua ammonia as the working fluid. Hot producedfluid from the formation may pass through line 212 to heat exchanger214. The produced fluid may have a temperature greater than about 100°C. Line 216 from heat exchanger 214 may direct the produced fluid to aseparator or other treatment unit. In some embodiments, the producedfluid is a mineral containing fluid produced during solution mining. Insome embodiments, the produced fluid includes hydrocarbons producedusing an in situ conversion process or using an in situ mobilizationprocess. Heat from the produced fluid is used to evaporate aqua ammoniain heat exchanger 214.

Aqua ammonia from tank 218 is directed by pump 220 to heat exchanger 214and heat exchanger 222. Aqua ammonia from heat exchangers 214, 222passes to separator 224. Separator 224 forms a rich ammonia gas streamand a lean ammonia gas stream. The rich ammonia gas stream is sent toturbine 226 to generate electricity.

The lean ammonia gas stream from separator 224 passes through heatexchanger 222. The lean gas stream leaving heat exchanger 222 iscombined with the rich ammonia gas stream leaving turbine 226. Thecombination stream is passed through heat exchanger 228 and returned totank 218. Heat exchanger 228 may be water cooled. Heater water from heatexchanger 228 may be sent to a surface water reservoir through line 230.

FIG. 4 depicts a schematic representation of a modified Kalina cyclethat uses lower pressure aqua ammonia as the working fluid. Hot producedfluid from the formation may pass through line 212 to heat exchanger214. The produced fluid may have a temperature greater than about 100°C. Second heat exchanger 232 may further reduce the temperature of theproduced fluid from the formation before the fluid is sent through line216 to a separator or other treatment unit. Second heat exchanger may bewater cooled.

Aqua ammonia from tank 218 is directed by pump 220 to heat exchanger234. The temperature of the aqua ammonia from tank 218 is heated in heatexchanger 234 by transfer with a combined aqua ammonia stream fromturbine 226 and separator 224. The aqua ammonia stream from heatexchanger 234 passes to heat exchanger 236. The temperature of thestream is raised again by transfer of heat with a lean ammonia streamthat exits separator 224. The stream then passes to heat exchanger 214.Heat from the produced fluid is used to evaporate aqua ammonia in heatexchanger 214. The aqua ammonia passes to separator 224

Separator 224 forms a rich ammonia gas stream and a lean ammonia gasstream. The rich ammonia gas stream is sent to turbine 226 to generateelectricity. The lean ammonia gas stream passes through heat exchanger236. After heat exchanger 236, the lean ammonia gas stream is combinedwith the rich ammonia gas stream leaving turbine 226. The combined gasstream is passed through heat exchanger 234 to cooler 238. After cooler238, the stream returns to tank 218.

In some embodiments, formation fluid produced from the in situconversion process is sent to a separator to split the stream into oneor more in situ conversion process liquid streams and/or one or more insitu conversion process gas streams. The liquid streams and the gasstreams may be further treated to yield desired products.

In some embodiments, in situ process conversion gas is treated at thesite of the formation to produce hydrogen. Treatment processes toproduce hydrogen from the in situ process conversion gas may includesteam methane reforming, autothermal reforming, and/or partial oxidationreforming.

All or at least a portion of a gas stream may be treated to yield a gasthat meets natural gas pipeline specifications. FIGS. 5, 6, 7, 8, and 9depict schematic representations of embodiments of systems for producingpipeline gas from the in situ conversion process gas stream.

As depicted in FIG. 5, in situ conversion process gas 240 enters unit242. In unit 242, treatment of in situ conversion process gas 240removes sulfur compounds, carbon dioxide, and/or hydrogen to produce gasstream 244. Unit 242 may include a physical treatment system and/or achemical treatment system. The physical treatment system includes, butis not limited to, a membrane unit, a pressure swing adsorption unit, aliquid absorption unit, and/or a cryogenic unit. The chemical treatmentsystem may include units that use amines (for example, diethanolamine ordi-isopropanolamine), zinc oxide, sulfolane, water, or mixtures thereofin the treatment process. In some embodiments, unit 242 uses a Sulfinolgas treatment process for removal of sulfur compounds. Carbon dioxidemay be removed using Catacarb® (Catacarb, Overland Park, Kans., U.S.A.)and/or Benfield (UOP, Des Plaines, Ill., U.S.A.) gas treatmentprocesses.

Gas stream 244 may include, but is not limited to, hydrogen, carbonmonoxide, methane, and hydrocarbons having a carbon number of at least 2or mixtures thereof. In some embodiments, gas stream 244 includesnitrogen and/or rare gases such as argon or helium. In some embodiments,gas stream 244 includes from about 0.0001 grams (g) to about 0.1 g, fromabout 0.001 g to about 0.05 g, or from about 0.01 g to about 0.03 g ofhydrogen, per gram of gas stream. In certain embodiments, gas stream 244includes from about 0.01 g to about 0.6 g, from about 0.1 g to about 0.5g, or from about 0.2 g to 0.4 g of methane, per gram of gas stream.

In some embodiments, gas stream 244 includes from about 0.00001 g toabout 0.01 g, from about 0.0005 g to about 0.005 g, or from about 0.0001g to about 0.001 g of carbon monoxide, per gram of gas stream. Incertain embodiments, gas stream 244 includes trace amounts of carbondioxide.

In certain embodiments, gas stream 244 may include from about 0.0001 gto about 0.5 g, from about 0.001 g to about 0.2 g, or from about 0.01 gto about 0.1 g of hydrocarbons having a carbon number of at least 2, pergram of gas stream. Hydrocarbons having a carbon number of at least 2include paraffins and olefins. Paraffins and olefins include, but arenot limited to, ethane, ethylene, acetylene, propane, propylene,butanes, butylenes, or mixtures thereof. In some embodiments,hydrocarbons having a carbon number of at least 2 include from about0.0001 g to about 0.5 g, from about 0.001 g to about 0.2 g, or fromabout 0.01 g to about 0.1 g of a mixture of ethylene, ethane, andpropylene. In some embodiments, hydrocarbons having a carbon number ofat least 2 includes trace amounts of hydrocarbons having a carbon numberof at least 4.

Pipeline gas (for example, natural gas) after treatment to remove thehydrogen sulfide, includes methane, ethane, propane, butane, carbondioxide, oxygen, nitrogen, and small amounts of rare gases. Typically,treated natural gas includes, per gram of natural gas, about 0.7 g toabout 0.98 g of methane; about 0.0001 g to about 0.2 g or from about0.001 g to about 0.05 g of a mixture of ethane, propane, and butane;about 0.0001 g to about 0.8 g or from about 0.001 g to about 0.02 g ofcarbon dioxide; about 0.00001 g to about 0.02 g or from about 0.0001 toabout 0.002 of oxygen; trace amounts of rare gases; and the balancebeing nitrogen. Such treated natural gas has a heat content of about 40MJ/Nm³ to about 50 MJ/Nm³.

Since gas stream 244 differs in composition from treated natural gas,gas stream 244 may not meet pipeline gas requirements. Emissionsgenerated during burning of gas stream 244 may be unacceptable and/ornot meet regulatory standards if the gas stream is to be used as a fuel.Gas stream 244 may include components or amounts of components that makethe gas stream undesirable for use as a feed stream for makingadditional products.

In some embodiments, hydrocarbons having a carbon number greater than 2are separated from gas stream 244. These hydrocarbons may be separatedusing cryogenic processes, adsorption processes, and/or membraneprocesses. Removal of hydrocarbons having a carbon number greater than 2from gas stream 244 may facilitate and/or enhance further processing ofthe gas stream.

Process units as described herein may be operated at the followingtemperatures, pressures, hydrogen source flows, and gas stream flows, oroperated otherwise as known in the art. Temperatures may range fromabout 50° C. to about 600° C., from about 100° C. to about 500° C., orfrom about 200° C. to about 400° C. Pressures may range from about 0.1MPa to about 20 MPa, from about 1 MPa to about 12 MPa, from about 4 MPato about 10 MPa, or from about 6 MPa to about 8 MPa. Flows of gasstreams through units described herein may range from about 5 metrictons of gas stream per day (“MT/D”) to about 15,000 MT/D. In someembodiments, flows of gas streams through units described herein rangefrom about 10 MT/D to 10,000 MT/D or from about 15 MT/D to about 5,000MT/D. In some embodiments, the hourly volume of gas processed is 5,000to 25,000 times the volume of catalyst in one or more processing units.

As depicted in FIG. 5, gas stream 244 and hydrogen source 246 enterhydrogenation unit 248. Hydrogen source 246 includes, but is not limitedto, hydrogen gas, hydrocarbons, and/or any compound capable of donatinga hydrogen atom. In some embodiments, hydrogen source 246 is mixed withgas stream 244 prior to entering hydrogenation unit 248. In someembodiments, the hydrogen source is hydrogen and/or hydrocarbons presentin gas stream 244. In hydrogenation unit 248, contact of gas stream 244with hydrogen source 246 in the presence of one or more catalystshydrogenates unsaturated hydrocarbons in gas stream 244 and produces gasstream 250. Gas stream 250 may include hydrogen and saturatedhydrocarbons such as methane, ethane, and propane. Hydrogenation unit248 may include a knock-out pot. The knock-out pot removes any heavyby-products 252 from the product gas stream.

Gas stream 250 exits hydrogenation unit 248 and enters hydrogenseparation unit 254. Hydrogen separation unit 254 is any suitable unitcapable of separating hydrogen from the incoming gas stream. Hydrogenseparation unit 254 may be a membrane unit, a pressure swing adsorptionunit, a liquid absorption unit, or a cryogenic unit. In certainembodiments, hydrogen separation unit 254 is a membrane unit. Hydrogenseparation unit 254 may include PRISM® membranes available from AirProducts and Chemicals, Inc. (Allentown, Pa., U.S.A.). The membraneseparation unit may be operated at a temperature ranging from about 50°C. to about 80° C. (for examples, at a temperature of about 66° C.). Inhydrogen separation unit 254, separation of hydrogen from gas stream 250produces hydrogen rich stream 256 and gas stream 258. Hydrogen richstream 256 may be used in other processes, or, in some embodiments, ashydrogen source 246 for hydrogenation unit 248.

In some embodiments, hydrogen separation unit 254 is a cryogenic unit.When hydrogen separation unit 254 is a cryogenic unit, gas stream 250may be separated into a hydrogen rich stream, a methane rich stream,and/or a gas stream that contains components having a boiling pointgreater than or equal to ethane.

In some embodiments, hydrogen content in gas stream 258 is acceptableand further separation of hydrogen from gas stream 258 is not needed.When the hydrogen content in gas stream 258 is acceptable, the gasstream may be suitable for use as pipeline gas.

Further removal of hydrogen from gas stream 258 may be desired. In someembodiments, hydrogen is separated from gas stream 258 using a membrane.An example of a hydrogen separation membrane is described in U.S. Pat.No. 6,821,501 to Matzakos et al, which is incorporated by reference asif fully set forth herein.

In some embodiments, a method of removing hydrogen from gas stream 258includes converting hydrogen to water. Gas stream 258 exits hydrogenseparation unit 254 and enters oxidation unit 260, as shown in FIG. 5.Oxidation source 262 also enters oxidation unit 260. In oxidation unit260, contact of gas stream 258 with oxidation source 262 produces gasstream 264. Gas stream 264 may include water produced as a result of theoxidation. The oxidation source may include, but is not limited to, pureoxygen, air, or oxygen enriched air. Since air or oxygen enriched airincludes nitrogen, monitoring the quantity of air or oxygen enriched airprovided to oxidation unit 260 may be desired to ensure the product gasmeets the desired pipeline specification for nitrogen. Oxidation unit260 includes, in some embodiments, a catalyst. Oxidation unit 260 is, insome embodiments, operated at a temperature in a range from about 50° C.to 500° C., from about 100° C. to about 400° C., or from about 200° C.to about 300° C.

Gas stream 264 exits oxidation unit 260 and enters dehydration unit 266.In dehydration unit 266, separation of water from gas stream 264produces pipeline gas 268 and water 270. Dehydration unit 266 may be,for example, a standard gas plant glycol dehydration unit and/ormolecular sieves.

In some embodiments, a change in the amount of methane in pipeline gasproduced from an in situ conversion process gas is desired. The amountof methane in pipeline gas may be enhanced through removal of componentsand/or through chemical modification of components in the in situconversion process gas.

FIG. 6 depicts a schematic representation of an embodiment to enhancethe amount of methane in pipeline gas through reformation andmethanation of the in situ conversion process gas.

Treatment of in situ conversion process gas as described herein producesgas stream 244. Gas stream 244, hydrogen source 246, and steam source272 enter reforming unit 274. In some embodiments, gas stream 244,hydrogen source 246, and/or steam source 272 are mixed together prior toentering reforming unit 274. In some embodiments, gas stream 244includes an acceptable amount of a hydrogen source, and thus externaladdition of hydrogen source 246 is not needed. In reforming unit 274,contact of gas stream 244 with hydrogen source 246 in the presence ofone or more catalysts and steam source 272 produces gas stream 276. Thecatalysts and operating parameters may be selected such that reformingof methane in gas stream 244 is minimized. Gas stream 276 includesmethane, carbon monoxide, carbon dioxide, and/or hydrogen. The carbondioxide in gas stream 276, at least a portion of the carbon monoxide ingas stream 276, and at least a portion of the hydrogen in gas stream 276is from conversion of hydrocarbons with a carbon number greater than 2(for example, ethylene, ethane, or propylene) to carbon monoxide andhydrogen. Methane in gas stream 276, at least a portion of the carbonmonoxide in gas stream 276, and at least a portion of the hydrogen ingas stream 276 is from gas stream 244 and hydrogen source 246.

Reforming unit 274 may be operated at temperatures and pressuresdescribed herein, or operated otherwise as known in the art. In someembodiments, reforming unit 274 is operated at temperatures ranging fromabout 250° C. to about 500° C. In some embodiments, pressures inreforming unit 274 range from about 1 MPa to about 5 MPa.

Removal of excess carbon monoxide in gas stream 276 to meet, forexample, pipeline specifications may be desired. Carbon monoxide may beremoved from gas stream 276 using a methanation process. Methanation ofcarbon monoxide produces methane and water. Gas stream 276 exitsreforming unit 274 and enters methanation unit 278. In methanation unit278, contact of gas stream 276 with a hydrogen source in the presence ofone or more catalysts produces gas stream 280. The hydrogen source maybe provided by hydrogen and/or hydrocarbons present in gas stream 276.In some embodiments, an additional hydrogen source is added to themethanation unit and/or the gas stream. Gas stream 280 may includewater, carbon dioxide, and methane.

Methanation unit 278 may be operated at temperatures and pressuresdescribed herein or operated otherwise as known in the art. In someembodiments, methanation unit 278 is operated at temperatures rangingfrom about 260° C. to about 320° C. In some embodiments, pressures inmethanation unit 278 range from about 1 MPa to about 5 MPa.

Carbon dioxide may be separated from gas stream 280 in carbon dioxideseparation unit 282. In some embodiments, gas stream 280 exitsmethanation unit 278 and passes through a heat exchanger prior toentering carbon dioxide separation unit 282. In carbon dioxideseparation unit 282, separation of carbon dioxide from gas stream 280produces gas stream 284 and carbon dioxide stream 286. In someembodiments, the separation process uses amines to facilitate theremoval of carbon dioxide from gas stream 280. Gas stream 284 includes,in some embodiments, at most 0.1 g, at most 0.08 g, at most 0.06, or atmost 0.04 g of carbon dioxide per gram of gas stream. In someembodiments, gas stream 284 is substantially free of carbon dioxide.

Gas stream 284 exits carbon dioxide separation unit 282 and entersdehydration unit 266. In dehydration unit 266, separation of water fromgas stream 284 produces pipeline gas 268 and water 270.

FIG. 7 depicts a schematic representation of an embodiment to enhancethe amount of methane in pipeline gas through concurrent hydrogenationand methanation of in situ conversion process gas. Hydrogenation andmethanation of carbon monoxide and hydrocarbons having a carbon numbergreater than 2 in the in situ conversion process gas produces methane.Concurrent hydrogenation and methanation in one processing unit mayinhibit formation of impurities. Inhibiting the formation of impuritiesenhances production of methane from the in situ conversion process gas.In some embodiments, the hydrogen source content of the in situconversion process gas is acceptable and an external source of hydrogenis not needed.

Treatment of in situ conversion process gas as described herein producesgas stream 244. Gas stream 244 enters hydrogenation and methanation unit288. In hydrogenation and methanation unit 288, contact of gas stream244 with a hydrogen source in the presence of a catalyst or multiplecatalysts produces gas stream 290. The hydrogen source may be providedby hydrogen and/or hydrocarbons in gas stream 244. In some embodiments,an additional hydrogen source is added to hydrogenation and methanationunit 288 and/or gas stream 244. Gas stream 290 may include methane,hydrogen, and, in some embodiments, at least a portion of gas stream244. In some embodiments, gas stream 290 includes from about 0.05 g toabout 1 g, from about 0.8 g to about 0.99 g, or from about 0.9 g to 0.95g of methane, per gram of gas stream. Gas stream 290 may include, pergram of gas stream, at most 0.1 g of hydrocarbons having a carbon numberof at least 2 and at most 0.01 g of carbon monoxide. In someembodiments, gas stream 290 includes trace amounts of carbon monoxideand/or hydrocarbons having a carbon number of at least 2.

Hydrogenation and methanation unit 288 may be operated at temperatures,and pressures, described herein, or operated otherwise as known in theart. In some embodiments, hydrogenation and methanation unit 288 isoperated at a temperature ranging from about 200° C. to about 350° C. Insome embodiments, pressure in hydrogenation and methanation unit 288 isabout 2 MPa to about 12 MPa, about 4 MPa to about 10 MPa, or about 6 MPato about 8 MPa. In certain embodiments, pressure in hydrogenation andmethanation unit 288 is about 4 MPa.

The removal of hydrogen from gas stream 290 may be desired. Removal ofhydrogen from gas stream 290 may allow the gas stream to meet pipelinespecification and/or handling requirements.

In FIG. 7, gas stream 290 exits methanation unit 288 and enterspolishing unit 292. Carbon dioxide stream 294 also enters polishing unit292, or it mixes with gas stream 290 upstream of the polishing unit. Inpolishing unit 292, contact of the gas stream 290 with carbon dioxidestream 294 in the presence of one or more catalysts produces gas stream296. The reaction of hydrogen with carbon dioxide produces water andmethane. Gas stream 296 may include methane, water, and, in someembodiments, at least a portion of gas stream 290. In some embodiments,polishing unit 292 is a portion of hydrogenation and methanation unit288 with a carbon dioxide feed line.

Polishing unit 292 may be operated at temperatures and pressuresdescribed herein, or operated as otherwise known in the art. In someembodiments, polishing unit 292 is operated at a temperature rangingfrom about 200° C. to about 400° C. In some embodiments, pressure inpolishing unit 292 is about 2 MPa to about 12 MPa, about 4 MPa to about10 MPa, or about 6 MPa to about 8 MPa. In certain embodiments, pressurein polishing unit 292 is about 4 MPa.

Gas stream 296 enters dehydration unit 266. In dehydration unit 266,separation of water from gas stream 296 produces pipeline gas 268 andwater 270.

FIG. 8 depicts a schematic representation of an embodiment to enhancethe amount of methane in pipeline gas through concurrent hydrogenationand methanation of in situ conversion process gas in the presence ofexcess carbon dioxide and the separation of ethane and heavierhydrocarbons. Hydrogen not used in the hydrogenation methanation processmay react with carbon dioxide to form water and methane. Water may thenbe separated from the process stream. Concurrent hydrogenation andmethanation in the presence of carbon dioxide in one processing unit mayinhibit formation of impurities.

Treatment of in situ conversion process gas as described herein producesgas stream 244. Gas stream 244 and carbon dioxide stream 294 enterhydrogenation and methanation unit 298. In hydrogenation and methanationunit 298, contact of gas stream 244 with a hydrogen source in thepresence of one or more catalysts and carbon dioxide produces gas stream300. The hydrogen source may be provided by hydrogen and/or hydrocarbonsin gas stream 244. In some embodiments, the hydrogen source is added tohydrogenation and methanation unit 298 or to gas stream 244. Thequantity of hydrogen in hydrogenation and methanation unit 298 may becontrolled and/or the flow of carbon dioxide may be controlled toprovide a minimum quantity of hydrogen in gas stream 300.

Gas stream 300 may include water, hydrogen, methane, ethane, and, insome embodiments, at least a portion of the hydrocarbons having a carbonnumber greater than 2 from gas stream 244. In some embodiments, gasstream 300 includes from about 0.05 g to about 0.7 g, from about 0.1 gto about 0.6 g, or from about 0.2 g to 0.5 g of methane, per gram of gasstream. Gas stream 300 includes from about 0.0001 g to about 0.4 g, fromabout 0.001 g to about 0.2 g, or from about 0.01 g to 0.1 g of ethane,per gram of gas stream. In some embodiments, gas stream 300 includes atrace amount of carbon monoxide and olefins.

Hydrogenation and methanation unit 298 may be operated at temperaturesand pressures, described herein, or operated otherwise as known in theart. In some embodiments, hydrogenation and methanation unit 298 isoperated at a temperature ranging from about 60° C. to about 350° C. anda pressure ranging from about 1 MPa to about 12 MPa, about 2 MPa toabout 10 MPa, or about 4 MPa to about 8 MPa.

In some embodiments, separation of ethane from methane is desirable.Separation may be performed using membrane and/or cryogenic techniques.Cryogenic processes may require that water levels in a gas stream be atmost 1-10 part per million by weight.

Water in gas stream 300 may be removed using generally known waterremoval techniques. Gas stream 300 exits hydrogenation and methanationunit 298, passes through heat exchanger 302 and then enters dehydrationunit 266. In dehydration unit 266, separation of water from gas stream300 as previously described, as well as by contact with absorption unitsand/or molecular sieves, produces gas stream 304 and water 270. Gasstream 304 may have a water content of at most 10 ppm, at most 5 ppm, orat most 1 ppm. In some embodiments, water content in gas stream 304ranges from about 0.01 ppm to about 10 ppm, from about 0.05 ppm to about5 ppm, or from about 0.1 ppm to about 1 ppm.

Cryogenic separator 306 separates gas stream 304 into pipeline gas 268and hydrocarbon stream 308. Pipeline gas stream 268 includes methaneand/or carbon dioxide. Hydrocarbon stream 308 includes ethane and, insome embodiments, residual hydrocarbons having a carbon number of atleast 2. In some embodiments, hydrocarbons having a carbon number of atleast 2 may be separated into ethane and additional hydrocarbons and/orsent to other operating units.

FIG. 9 depicts a schematic representation of an embodiment to enhancethe amount of methane in pipeline gas through concurrent hydrogenationand methanation of in situ conversion process gas in the presence ofexcess hydrogen. The use of excess hydrogen during the hydrogenation andmethanation process may prolong catalyst life, control reaction rates,and/or inhibit formation of impurities.

Treatment of in situ conversion process gas as described herein producesgas stream 244. Gas stream 244 and hydrogen source 246 enterhydrogenation and methanation unit 310. In some embodiments, hydrogensource 246 is added to gas stream 244. In hydrogenation and methanationunit 310, contact of gas stream 244 with hydrogen source 246 in thepresence of one or more catalysts produces gas stream 312. In someembodiments, carbon dioxide may be added to hydrogen and methanationunit 310. The quantity of hydrogen in hydrogenation and methanation unit310 may be controlled to provide an excess quantity of hydrogen to thehydrogenation and methanation unit.

Gas stream 312 may include water, hydrogen, methane, ethane, and, insome embodiments, at least a portion of the hydrocarbons having a carbonnumber greater than 2 from gas stream 244. In some embodiments, gasstream 312 includes from about 0.05 g to about 0.9 g, from about 0.1 gto about 0.6 g, or from about 0.2 g to 0.5 g of methane, per gram of gasstream. Gas stream 312 includes from about 0.0001 g to about 0.4 g, fromabout 0.001 g to about 0.2 g, or from about 0.01 g to 0.1 g of ethane,per gram of gas stream. In some embodiments, gas stream 312 includescarbon monoxide and trace amounts of olefins.

Hydrogenation and methanation unit 310 may be operated at temperaturesand pressures, described herein, or operated otherwise as known in theart. In some embodiments, hydrogenation and methanation unit 310 isoperated at a temperature ranging from about 60° C. to about 400° C. anda hydrogen partial pressure ranging from about 1 MPa to about 12 MPa,about 2 MPa to about 8 MPa, or about 3 MPa to about 5 MPa. In someembodiments, the hydrogen partial pressure in hydrogenation andmethanation unit 310 is about 3 MPa.

Gas stream 312 enters gas separation unit 314. Gas separation unit 314is any suitable unit or combination of units that is capable ofseparating hydrogen and/or carbon dioxide from gas stream 312. Gasseparation unit may be a pressure swing adsorption unit, a membraneunit, a liquid absorption unit, and/or a cryogenic unit. In someembodiments, gas stream 312 exits hydrogenation and methanation unit 310and passes through a heat exchanger prior to entering gas separationunit 314. In gas separation unit 314, separation of hydrogen from gasstream 312 produces gas stream 316 and hydrogen stream 318. Hydrogenstream 318 may be recycled to hydrogenation and methanation unit 310,mixed with gas stream 244 and/or mixed with hydrogen source 246 upstreamof the hydrogenation methanation unit. In embodiments in which carbondioxide is added to hydrogenation and methanation unit 310, carbondioxide is separated from gas stream 316 in separation unit 314. Theseparated carbon dioxide may be recycled to the hydrogenation andmethanation unit, mixed with gas stream 244 upstream of thehydrogenation and methanation unit, and/or mixed with the carbon dioxidestream entering the hydrogenation and methanation unit.

Gas stream 316 enters dehydration unit 266. In dehydration unit 266,separation of water from gas stream 316 produces pipeline gas 268 andwater 270.

It should be understood that gas stream 244 may be treated bycombinations of one or more of the processes described in FIGS. 5, 6, 7,8, and 9. For example, all or at least a portion of gas streams fromreforming unit 274 (FIG. 6) may be treated in hydrogenation andmethanation units 288 (FIG. 7), 298 (FIG. 8), or 308 (FIG. 9). All or atleast a portion of the gas stream produced from hydrogenation unit 248may enter, or be combined with gas streams entering, reforming unit 274,hydrogenation and methanation unit 288, and/or hydrogenation andmethanation unit 298. In some embodiments, gas stream 244 may behydrotreated and/or used in other processing units.

Catalysts used to produce natural gas that meets pipeline specificationsmay be bulk metal catalysts or supported catalysts. Bulk metal catalystsinclude Columns 6-10 metals. Supported catalysts include Columns 6-10metals on a support. Columns 6-10 metals include, but are not limitedto, vanadium, chromium, molybdenum, tungsten, manganese, technetium,rhenium, iron, cobalt, nickel, ruthenium, palladium, rhodium, osmium,iridium, platinum, or mixtures thereof. The catalyst may have, per gramof catalyst, a total Columns 6-10 metals content of at least 0.0001 g,at least 0.001 g, at least 0.01 g, or in a range from about 0.0001-0.6g, about 0.005-0.3 g, about 0.001-0.1 g, or about 0.01-0.08 g. In someembodiments, the catalyst includes a Column 15 element in addition tothe Columns 6-10 metals. An example of a Column 15 element isphosphorus. The catalyst may have a total Column 15 elements content,per gram of catalyst, in a range from about 0.000001-0.1 g, about0.00001-0.06 g, about 0.00005-0.03 g, or about 0.0001-0.001 g. In someembodiments, the catalyst includes a combination of Column 6 metals withone or more Columns 7-10 metals. A molar ratio of Column 6 metals toColumns 7-10 metals may be in a range from 0.1-20, 1-10, or 2-5. In someembodiments, the catalyst includes Column 15 elements in addition to thecombination of Column 6 metals with one or more Columns 7-10 metals.

In some embodiments, Columns 6-10 metals are incorporated in, ordeposited on, a support to form the catalyst. In certain embodiments,Columns 6-10 metals in combination with Column 15 elements areincorporated in, or deposited on, the support to form the catalyst. Inembodiments in which the metals and/or elements are supported, theweight of the catalyst includes all support, all metals, and allelements. The support may be porous and may include refractory oxides;oxides of tantalum, niobium, vanadium, scandium, or lanthanide metals;porous carbon based materials; zeolites; or combinations thereof.Refractory oxides may include, but are not limited to, alumina, silica,silica-alumina, titanium oxide, zirconium oxide, magnesium oxide, ormixtures thereof. Supports may be obtained from a commercialmanufacturer such as CRI/Criterion Inc. (Houston, Tex., U.S.A.). Porouscarbon based materials include, but are not limited to, activated carbonand/or porous graphite. Examples of zeolites include Y-zeolites, betazeolites, mordenite zeolites, ZSM-5 zeolites, and ferrierite zeolites.Zeolites may be obtained from a commercial manufacturer such as Zeolyst(Valley Forge, Pa., U.S.A.).

Supported catalysts may be prepared using generally known catalystpreparation techniques. Examples of catalyst preparations are describedin U.S. Pat. Nos. 6,218,333 to Gabrielov et al.; 6,290,841 to Gabrielovet al.; 5,744,025 to Boon et al., and 6,759,364 to Bhan, all of whichare incorporated by reference herein.

In some embodiments, the support is impregnated with metal to form thecatalyst. In certain embodiments, the support is heat treated attemperatures in a range from about 400° C. to about 1200° C., from about450° C. to about 1000° C., or from about 600° C. to about 900° C. priorto impregnation with a metal. In some embodiments, impregnation aids areused during preparation of the catalyst. Examples of impregnation aidsinclude a citric acid component, ethylenediaminetetraacetic acid (EDTA),ammonia, or mixtures thereof.

The Columns 6-10 metals and support may be mixed with suitable mixingequipment to form a Columns 6-10 metals/support mixture. The Columns6-10 metals/support mixture may be mixed using suitable mixingequipment. Examples of suitable mixing equipment include tumblers,stationary shells or troughs, Muller mixers (batch type or continuoustype), impact mixers, and any other generally known mixer, or otherdevice, that will suitably provide the Columns 6-10 metals supportmixture. In certain embodiments, the materials are mixed until theColumns 6-10 metals are substantially homogeneously dispersed in thesupport.

In some embodiments, the catalyst is heat treated at temperatures from150-750° C., from 200-740° C., or from 400-730° C. after combining thesupport with the metal. In some embodiments, the catalyst is heattreated in the presence of hot air and/or oxygen rich air at atemperature in a range between 400° C. and 1000° C. to remove volatilematter and to convert at least a portion of the Columns 6-10 metals tothe corresponding metal oxide.

In other embodiments, a catalyst precursor is heat treated in thepresence of air at temperatures in a range from 35-500° C. for a periodof time in a range from 1-3 hours to remove a majority of the volatilecomponents without converting the Columns 6-10 metals to thecorresponding metal oxide. Catalysts prepared by such a method aregenerally referred to as “uncalcined” catalysts. When catalysts areprepared in this manner, in combination with a sulfiding method, theactive metals may be substantially dispersed in the support.Preparations of such catalysts are described in U.S. Pat. Nos. 6,218,333to Gabrielov et al., and 6,290,841 to Gabrielov et al.

In some embodiments, the catalyst and/or a catalyst precursor issulfided to form metal sulfides (prior to use) using techniques known inthe art (for example, ACTICAT™ process, CRI International, Inc.(Houston, Tex., U.S.A.)). In some embodiments, the catalyst is driedthen sulfided. Alternatively, the catalyst may be sulfided in situ bycontact of the catalyst with a gas stream that includessulfur-containing compounds. In situ sulfurization may utilize eithergaseous hydrogen sulfide in the presence of hydrogen or liquid-phasesulfurizing agents such as organosulfur compounds (includingalkylsulfides, polysulfides, thiols, and sulfoxides). Ex-situsulfurization processes are described in U.S. Pat. Nos. 5,468,372 toSeamans et al., and 5,688,736 to Seamans et al., all of which areincorporated by reference herein.

In some embodiments, a first type of catalyst (“first catalyst”)includes Columns 6-10 metals and the support. The first catalyst is, insome embodiments, an uncalcined catalyst. In some embodiments, the firstcatalyst includes molybdenum and nickel. In certain embodiments, thefirst catalyst includes phosphorus. In some embodiments, the firstcatalyst includes Columns 9-10 metals on a support. The Column 9 metalmay be cobalt and the Column 10 metal may be nickel. In someembodiments, the first catalyst includes Columns 10-11 metals. TheColumn 10 metal may be nickel and the Column 11 metal may be copper.

The first catalyst may assist in the hydrogenation of olefins toalkanes. In some embodiments, the first catalyst is used in thehydrogenation unit. The first catalyst may include at least 0.1 g, atleast 0.2 g, or at least 0.3 g of Column 10 metals per gram of support.In some embodiments, the Column 10 metal is nickel. In certainembodiments, the Column 10 metal is palladium and/or a mixed alloy ofplatinum and palladium. Use of a mixed alloy catalyst may enhanceprocessing of gas streams with sulfur containing compounds. In someembodiments, the first catalyst is a commercial catalyst. Examples ofcommercial first catalysts include, but are not limited to, Criterion424, DN-140, DN-200, and DN-3100, KL6566, KL6560, KL6562, KL6564,KL7756; KL7762, KL7763, KL7731, C-624, C654, all of which are availablefrom CRI/Criterion Inc.

In some embodiments, a second type of catalyst (“second catalyst”)includes Column 10 metal on a support. The Column 10 metal may beplatinum and/or palladium. In some embodiments, the catalyst includesabout 0.001 g to about 0.05 g, or about 0.01 g to about 0.02 g ofplatinum and/or palladium per gram of catalyst. The second catalyst mayassist in the oxidation of hydrogen to form water. In some embodiments,the second catalyst is used in the oxidation unit. In some embodiments,the second catalyst is a commercial catalyst. An example of commercialsecond catalyst includes KL87748, available from CRI/Criterion Inc.

In some embodiments, a third type of catalyst (“third catalyst”)includes Columns 6-10 metals on a support. In some embodiments, thethird catalyst includes Columns 9-10 metals on a support. The Column 9metal may be cobalt and the Column 10 metal may be nickel. In someembodiments, the content of nickel metal is from about 0.1 g to about0.3 g, per gram of catalyst. The support for a third catalyst mayinclude zirconia. The third catalyst may assist in the reforming ofhydrocarbons having a carbon number greater than 2 to carbon monoxideand hydrogen. The third catalyst may be used in the reforming unit. Insome embodiments, the third catalyst is a commercial catalyst. Examplesof commercial third catalysts include, but are not limited to, CRG-FRand/or CRG-LH available from Johnson Matthey (London, England).

In some embodiments, a fourth type of catalyst (“fourth catalyst”)includes Columns 6-10 metals on a support. In some embodiments, thefourth catalyst includes Column 8 metals in combination with Column 10metals on a support. The Column 8 metal may be ruthenium and the Column10 metal may be nickel, palladium, platinum, or mixtures thereof. Insome embodiments, the fourth catalyst support includes oxides oftantalum, niobium, vanadium, the lanthanides, scandium, or mixturesthereof. The fourth catalyst may be used to convert carbon monoxide andhydrogen to methane and water. In some embodiments, the fourth catalystis used in the methanation unit. In some embodiments, the fourthcatalyst is a commercial catalyst. Examples of commercial fourthcatalysts, include, but are not limited to, KATALCO® 11-4 and/orKATALCO® 11-4R available from Johnson Matthey.

In some embodiments, a fifth type of catalyst (“fifth catalyst”)includes Columns 6-10 metals on a support. In some embodiments, thefifth catalyst includes a Column 10 metal. The fifth catalyst mayinclude from about 0.1 g to about 0.99 g, from about 0.3 g to about 0.9g, from about 0.5 g to about 0.8 g, or from 0.6 g to about 0.7 g ofColumn 10 metal per gram of fifth catalyst. In some embodiments, theColumn 10 metal is nickel. In some embodiments, a catalyst that has atleast 0.5 g of nickel per gram of fifth catalyst has enhanced stabilityin a hydrogenation and methanation process. The fifth catalyst mayassist in the conversion of hydrocarbons and carbon dioxide to methane.The fifth catalyst may be used in hydrogenation and methanation unitsand/or polishing units. In some embodiments, the fifth catalyst is acommercial catalyst. An example of a commercial fifth catalyst isKL6524-T, available from CRI/Criterion Inc.

Formation fluid produced from the in situ conversion process may be sentto the separator to split the stream into the in situ conversion processliquid stream and the in situ conversion process gas stream. The liquidstream and the gas stream may be further treated to yield desiredproducts. When the liquid stream is treated using generally knownconditions to produce commercial products, processing equipment may beadversely affected. For example, the processing equipment may clog.Examples of processes to produce commercial products include, but arenot limited to, alkylation, distillation, hydrocracking, hydrotreating,hydrogenation, hydrodesulfurization, catalytic cracking, or combinationsthereof. Processes to produce commercial products are described in“Refning Processes 2000,” Hydrocarbon Processing, Gulf Publishing Co.,pp. 87-142, which is incorporated by reference herein. Examples ofcommercial products include, but are not limited to, diesel, gasoline,hydrocarbon gases, jet fuel, kerosene, naphtha, vacuum gas oil (“VGO”),or mixtures thereof.

Process equipment may become clogged by compositions in the in situconversion process liquid. Compositions may include, but are not limitedto, hydrocarbons and/or solids produced from the in situ conversionprocess. Compositions that cause clogging may be formed during heatingof the in situ conversion process liquid. The compositions may adhere toparts of the equipment and inhibit the flow of the liquid stream throughprocessing units.

Solids may include, but are not limited to, organometallic compounds,inorganic compounds, minerals, mineral compounds, and/or mixturesthereof. The solids may have a particle size such that filtration maynot remove the solids from the liquid stream. Hydrocarbons may include,but are not limited to, hydrocarbons that contain heteroatoms, aromatichydrocarbon, cyclic hydrocarbons, cyclic olefins, and/or acyclicolefins. In some embodiments, solids and/or hydrocarbons present in thein situ conversion process liquid that cause clogging are partiallysoluble or insoluble in the situ conversion process liquid. In someembodiments, filtration of the liquid stream prior to or during heatingis insufficient and/or ineffective for removal of all or some of thecompositions that clog process equipment.

In some embodiments, clogging of process equipment is inhibited byhydrotreating at least a portion of the liquid stream. The hydrotreatedliquid stream may be further processed to produce commercial products.

FIG. 10 depicts a schematic representation of an embodiment of a systemfor producing crude products and/or commercial products from the in situconversion process liquid stream and/or the in situ conversion processgas stream Formation fluid 320 enters gas/liquid separation unit 322 andis separated into in situ conversion process liquid stream 324, in situconversion process gas 240, and aqueous stream 326.

In situ conversion process gas 240 may enter gas separation unit 328 toseparate gas hydrocarbon stream 330 from the in situ conversion processgas. The gas separation unit is, in some embodiments, a rectifiedadsorption unit. Gas hydrocarbon stream 330 includes hydrocarbons havinga carbon number of at least 3.

In situ conversion process liquid stream 324 enters liquid separationunit 332. In liquid separation unit 332, separation of in situconversion liquid stream 324 produces gas hydrocarbon stream 336 andliquid stream 334. Gas hydrocarbon stream 336 may include hydrocarbonshaving a carbon number of at most 5.

Liquid stream 334 includes, but is not limited to, hydrocarbons having acarbon number of at least 5 and/or hydrocarbon containing heteroatoms(for example, hydrocarbons containing nitrogen, oxygen, sulfur, andphosphorus). Liquid stream 334 may include at least 0.001 g, at least0.005 g, or at least 0.01 g of hydrocarbons with a boiling rangedistribution between 95° C. and 200° C. at 0.101 MPa; at least 0.01 g,at least 0.005 g, or at least 0.001 g of hydrocarbons with a boilingrange distribution between 200° C. and 300° C. at 0.101 MPa; at least0.001 g, at least 0.005 g, or at least 0.01 g of hydrocarbons with aboiling range distribution between 300° C. and 400° C. at 0.101 MPa; andat least 0.001 g, at least 0.005 g, or at least 0.01 g of hydrocarbonswith a boiling range distribution between 400° C. and 650° C. at 0.101MPa.

Process units as described herein for the production of crude productsand/or commercial products may be operated at the followingtemperatures, pressures, hydrogen source flows, liquid stream flows, orcombinations thereof, or operated otherwise as known in the art.Temperatures range from about 200° C. to about 800° C., from about 300°C. to about 700° C., or from about 400° C. to about 600° C. Pressuresrange from about 0.1 MPa to about 20 MPa, from about 1 MPa to about 12MPa, from about 4 MPa to about 10 MPa, or from about 6 MPa to about 8MPa. Liquid hourly space velocities (“LHSV”) of the liquid stream rangefrom about 0.1 h⁻¹ to about 30 h⁻¹, from about 0.5 h⁻¹ to about 25 h⁻¹,from about 1 h⁻¹ to about 20 h⁻¹, from about 1.5 h⁻¹ to about 15 h⁻¹, orfrom about 2 h⁻¹ to about 10 h⁻¹.

Liquid stream 334 and hydrogen source 246 enter hydrotreating unit 338.Hydrogen source 246 may be added to liquid stream 334 before enteringhydrotreating unit 338. In some embodiments, sufficient hydrogen ispresent in liquid stream 334 and hydrogen source 246 is not needed. Inhydrotreating unit 338, contact of liquid stream 334 with hydrogensource 246 in the presence of one or more catalysts produces liquidstream 340. Hydrotreating unit 338 may be operated such that all or atleast a portion of liquid stream 340 is changed sufficiently to removecompositions and/or inhibit formation of compositions that may clogequipment positioned downstream of the hydrotreating unit 338. Thecatalyst used in hydrotreating unit 338 may be a commercially availablecatalyst.

Liquid stream 340 exits hydrotreating unit 338 and enters one or moreprocessing units positioned downstream of hydrotreating unit 338. Theunits positioned downstream of hydrotreating unit 338 may includedistillation units, hydrocracking units, hydrotreating units,hydrogenation units, hydrodesulfinurization units, catalytic crackingunits, or combinations thereof.

Liquid stream 340 may exit hydrotreating unit 338 and enterfractionation unit 342. Fractionation unit 342 produces one or morecrude products. Fractionation may include, but is not limited to, anatmospheric distillation process and/or a vacuum distillation process.Crude products include, but are not limited to, C₃-C₅ hydrocarbon stream344, naphtha stream 346, kerosene stream 348, diesel stream 350, VGOstream 352, and bottoms stream 354. Bottoms stream 354 generallyincludes hydrocarbons having a boiling point range greater than 538° C.at 0.101 MPa. One or more of the crude products may be sold and/orfurther processed to gasoline or other commercial products.

To enhance the use of the streams produced from formation fluid,hydrocarbons produced during fractionation of the liquid stream andhydrocarbon gases produced during separating the process gas may becombined to form hydrocarbons having a higher carbon number. Theproduced hydrocarbon gas stream may include a level of olefinsacceptable for alkylation reactions.

C₃-C₅ hydrocarbon stream 344 produced from fractionation unit 342 andhydrocarbon gas stream 330 enter alkylation unit 356. In alkylation unit356, reaction of the olefins in hydrocarbon gas stream 330 (for example,ethylene and propylene) with the alkanes in C₃-C₅ hydrocarbon stream 344produces hydrocarbon stream 358. In some embodiments, the olefin contentin hydrocarbon gas stream 330 is acceptable and an additional source ofolefins is not needed. Hydrocarbon stream 358 includes hydrocarbonshaving a carbon number of at least 4. Hydrocarbons having a carbonnumber of at least 4 include, but are not limited to, butanes, pentanes,hexanes, and heptanes.

In some embodiments, bottoms stream 354 may be hydrocracked to producenaphtha and/or other products. The resulting naphtha may, however, needfortification to alter the octane level so that the product may be soldcommercially as gasoline. Alternatively, bottoms stream 354 may betreated in a catalytic cracker to produce high octane naphtha and/orfeed for an alkylation unit.

In FIG. 10, bottoms stream 354 from fractionation unit 342 enterscatalytic cracking unit 360. In catalytic cracking unit 360, contact ofbottoms stream 354 with a catalyst under controlled temperaturesproduces additional C₃-C₅ hydrocarbon stream 344′, gasoline stream 362,and additional kerosene stream 348′. Additional C₃-C₅ hydrocarbon stream344′ may be sent to alkylation unit 356, combined with C₃-C₅ hydrocarbonstream 344, and/or combined with hydrocarbon gas stream 330. In someembodiments, the olefin content in hydrocarbon gas stream 330 isacceptable and an additional source of olefins is not needed.

Heating a portion of the subsurface formation may cause the mineralstructure of the formation to change and form particles. The particlesmay be dispersed and/or become partially dissolved in the formationfluid. The particles may include metals and/or compounds of metals fromColumns 1-2 and Columns 4-13 of the Periodic Table (for example,aluminum, silicon, magnesium, calcium, potassium sodium, beryllium,lithium, chromium, magnesium, copper, zirconium, and so forth). In someembodiments, the particles are coated, for example, with hydrocarbons ofthe formation fluid. In certain embodiments, the particles includezeolites.

A concentration of particles in formation fluid may range from about 1ppm to about 3000 ppm, from about 50 ppm to about 2000 ppm, or fromabout 100 ppm to about 1000 ppm. The size of particles may range from0.5 micron to about 200 microns, from 5 micron to about 150 microns,from about 10 microns to about 100 microns, or about 20 microns to about50 microns.

In certain embodiments, formation fluid may include a distribution ofparticles. The distribution of particles may be, but is not limited to,a trimodal or a bimodal distribution. For example, a trimodaldistribution of particles may include from about 1 ppm to about 50 ppmof particles with a size of about 5 microns to about 10 microns, fromabout 2 ppm to about 2000 ppm of particles with a size of about 50microns to about 80 microns, and from about 1 ppm to about 100 ppm witha size of about 100 micron to about 200 microns. A bimodal distributionof particles may include from about 1 ppm to 60 ppm of particles with asize of between about 50 and 60 microns and from about 2 ppm to about2000 ppm of particles with a size between about 100 and 200 microns.

In some embodiments, the particles may contact the formation fluid andcatalyze formation of compounds having a carbon number of at most 25, atmost 20, at most 12, or at most 8. In certain embodiments, the zeoliticparticles may assist in the oxidation and/or reduction of formationfluids to produce compounds not generally found in fluids produced usingconventional production methods. Contact of formation fluid withhydrogen in the presence of zeolitic particles may catalyze reduction ofdouble bond compounds in the formation fluid.

In some embodiments, all or a portion of the particles in the producedfluid may be removed from the produced fluid. The particles may beremoved by using a centrifuge, by washing, by acid washing, byfiltration, by electrostatic precipitation, by froth flotation, and/orby another type of separation process.

Many wells are needed for treating a hydrocarbon formation using an insitu conversion process. In some embodiments, vertical or substantiallyvertical wells are formed in the formation. In some embodiments,horizontal or U-shaped wells are formed in the formation. In someembodiments, combinations of horizontal and vertical wells are formed inthe formation. Wells may be formed using drilling rigs.

In an embodiment, a rig for drilling wells includes equipment on the rigfor drilling multiple wellbores simultaneously. The rig may include oneor more systems for constructing the wells, including drilling, fluidhandling, and cementing of the wells through the overburden, drilling tototal depth, and placing completion equipment such as heaters andcasing. The rig may be particularly useful for forming closely spacedwells, such as freeze wells.

In some embodiments, wells are drilled in sequential stages withdifferent drilling machines. The wells may be barrier wells, heaterwells, production wells, production/heater wells, monitor wells,injection wells, or other types of wells. A conductor drilling machinemay set the conductor of the well. A main hole drilling machine maydrill the wellbore to depth. A completion drilling machine may placecasing, cement, tubing, cables, heaters, and perform other wellcompletion tasks. The drilling machines may be on the same locationmoving 3 to 10 meters between wells for 2 to 3 years. The size and theshape of the drilling machines may not have to meet existing roadtransportation regulations since once in the field, the drillingmachines may remain there for the duration of the project. The majorcomponents of the drilling machines may be transported to location andassembled there. The drilling machines may not have to be disassembledfor a multi-mile move for several years.

One or more central plants may support the drilling machines. The use ofa central plant may allow for smaller drilling machines. The centralplant may include prime movers, mud tanks, solids handling equipment,pipe handling, power, and other equipment common to the drillingmachines. The equipment of the central plant may be coupled to thedrilling machines by flexible umbilicals, by easily modifiable piping,and/or by quick release electrical connections. Several wells may bedrilled before the need to move the central plant arises. In someembodiments, the central plant may be moved while connected to one ormore operating drilling machines. The drilling machines and centralplant may be designed with integrated drip pans to capture leaks andspills.

In some embodiments, the drilling machines are powered directly off theelectric grid. In other embodiments, the drilling machines are dieselpowered. Using diesel power may avoid complications associated withinterfering with the installation of electrical and other systems neededfor the wells of the in situ conversion process.

The drilling machines may be automated so that little or no humaninteraction is required. The tubulars used by the drilling machines maybe stacked and stored on or by the drilling machines so that thedrilling machines can access and manipulate the tubulars with minimal orno human intervention. For example, a carousel or other device may beused to store a tubular and move the tubular from storage to thedrilling mast. The carousel or other device may also be used to move thetubular from the drilling mast to storage.

The drilling machines may include propulsion units so that the drillingmachines do not need to be skidded. The central plant may also includepropulsion units. Skidding involves extra equipment not used fordrilling the wells and may be complicated by the dense concentration ofsurface facilities and equipment. In some embodiments, the drillingmachines and/or central plant may include tracks or a walking mechanismto eliminate railroad-type tracks. Eliminating railroad-type tracks mayreduce the amount of pre-work road and rail formation that needs to becompleted before drilling operations can begin. In some embodiments, thepropulsion units may include a fixed-movement mechanism. Thefixed-movement mechanism may advance the drilling machine a set distancewhen activated so that the drilling machine is located at the next welllocation. Fine adjustment may allow for exact positioning of thedrilling machine after initial position location by the fixed-movementmechanism.

In some embodiments, drilling machines and/or the central plant arepositioned on a central track or access lane. The drilling equipment maybe extended from one side to the other of the central track to form thewells. The drilling machine is able to stay in one place while an arm orcantilever mechanism allows multiples of wells to be drilled around thedrilling machine. The wells may be drilled in very close proximity ifrequired.

The drilling machines and the central plant may be self-leveling andable to function on up to a 10% grade or higher. In some embodiments,the drilling machines include hydraulic and/or mechanical levelingsystems. The drilling machines and central plant may have groundclearances of at least 1 meter so that the units may be movedunobstructed over wellheads. Each drilling machine may include amechanism for precisely placing the working components of the drillingmachine over the hole center of the well being formed. In someembodiments, the mechanism adjusts the position of a derrick of thedrilling machine.

The drilling machines may be moved from one well to another withderricks of the drilling machines in upright or inclined positions. Theterm “derrick” is used to represent whatever top drive support device isemployed on the rig, whether the top drive support device is a derrick,stiff mast, or hydraulic arm. Because some drilling machines may usethree 10 m pipe sections, the derrick may have to be lowered for rigmoves. If the derrick must be lowered, lowering and raising the derrickneeds to be a quick and safe operation. In some embodiments, the derrickis lowered with the bottom hole assembly racked in the derrick to savetime handling the bottom hole assembly. In other embodiments, the bottomhole assembly is separated from the derrick for servicing during a moveof the drilling machine.

In some embodiments, one of the drilling machines is able to do morethan one stage of well formation. In some embodiments, a freeze wall orother barrier is formed around all or a portion of a treatment area.There may be about a year or more of time from when the last freeze wellis drilled to the time that main holes for heater and producer wells canbe drilled. In the intervening time, the drilling machine used to drillthe main hole of a well may be used to preset conductors for heaterwells and/or production wells in the treatment area.

In some embodiments, two or more drilling machines are placed on thesame carrier. For example, the carrier may include equipment thatpresets the conductor for a well. The carrier may also carry equipmentfor forming the main hole. One portion of the machine could bepresetting a conductor while another portion of the machine could besimultaneously forming the main hole of a second well.

Running drill pipe to replace bits, running in down hole equipment andpulling the equipment out after use may be time consuming and expensive.To save time and expense, all drilling and completion tools may go intothe hole and not come out. For example, drill pipe may become casing.Once data is obtained from logging runs, the logging tools are left inthe hole and drilling proceeds through them or past them if necessary.Downhole equipment is integrated into the drill pipe. In someembodiments, the drill pipe becomes a conduit of a conduit-in-conduitheater.

In some embodiments, a retractable drilling assembly is used. Using aretractable drilling assembly may be beneficial when using continuouscoiled tubing. When total depth of the well is reached, the drill bitand bottom hole assembly may be retracted to a smaller diameter. Thedrill bit and bottom hole assembly may be brought to the surface throughthe coiled tubing. The coiled tubing may be left in the hole as casing.

In some embodiments, the main hole drilling machine and the completiondrilling machine include a quick-connect device for attaching the fluiddiverter spool (drilling wellhead) to the conductor casing. The use of aquick-connect device may be faster than threading or welding thediverter to the conductor casing. The quick-connect device may be asnap-on or clamp-on type diverter. Wellheads are typically designed tofit a multitude of casing configurations, everything from 48 inchconductor to 2⅜ inch tubing. For an in situ conversion process, thewellheads may not need to span such a large casing diameter set or havemultiple string requirements. The wellheads may only handle a verylimited pipe diameter range and only one or two casing strings. Having afit for purpose wellhead may significantly reduce the cost offabricating and installing the wellheads for the wells of the in situconversion process.

In some embodiments, the main hole drilling machine includes aslickline/boom system. The slickline/boom system may allow runningranging equipment in a close offset well while drilling the well thedrilling machine is positioned over. The use of the slickline/boomsystem on the drilling machine may eliminate the need for additionalequipment for employing the ranging equipment.

In some embodiments, the conductor drilling machine is a blast-hole rig.The blast-hole rig may be mounted on a crawler or carrier with metaltracks. Air or gas compression is on board the blast-hole rig. Tubularsmay be racked horizontally on the blast-hole rig. The derrick of theblast-hole rig may be adjusted to hole center. The bottom hole drillingassembly of the blast-hole rig may be left in the derrick when theblast-hole rig is moved. In some embodiments, the blast-hole rigincludes an integral drilling fluid tank, solids control equipment, anda mist collector. In some embodiments, the drilling fluid tank, thesolids control equipment, and/or the mist collector is part of thecentral plant.

During well formation with jointed pipe, one time consuming task ismaking connections. To reduce the number of connections needed duringformation of wells, long lengths of pipe may be used. In someembodiments, the drilling machines are able to use pipe with a length ofabout 25 m to 30 m. The 25 m to 30 m piping may be made up of two ormore shorter joints, but is preferably a single joint of the appropriatelength. Using a single joint may decrease the complexity of pipehandling and result in fewer potential leak paths in the drill string.In some embodiments, the drilling machines use jointed pipe having otherlengths, such as 20 m lengths, or 10 m lengths.

The drilling machine may use a top drive system. In some embodiments,the top drive system functions using a rack and pinion. In someembodiments, the top drive system functions using a hydraulic system.

The drilling machines may include automated pipe handling systems. Theautomated pipe handling system may be able to lift pipe, makeconnections, and have another joint in the raised position ready for thenext connection. The automated pipe handling systems may include an ironroughneck to make and break connections. In some embodiments, the pipeskid for the drilling machine is an integral component of the drillingmachine.

String floats (check valves) may be needed in the drill string becauseair and/or liquid will be used during drilling. An integral float valvemay be positioned in each joint used by the drilling machine. Includinga string float in each joint may minimize circulating times atconnections and speed up the connection process.

Drilling the wells may be done at low operating pressures. In someembodiments, a quick-connect coupler is used to connect drill pipetogether because of the low operating pressures. Using quick-connectcouplers to join drill pipe may reduce drilling time and simplify pipehandling automation.

In certain embodiments, the main hole drilling machine is designed todrill 6¼ inch or 6½ inch holes. The pumping capabilities needed tosupport the main hole drilling machine may include 3×900 scfm aircompressors, a 2000 psi booster, and a liquid pump with an operationalmaximum of 325 gpm. A 35 gpm pump may also be included if mist drillingis required.

In some embodiments, the main hole drilling machine and/or thecompletion drilling machine uses coiled tubing. Coiled tubing may allowfor minimal or no pipe connections above the bottom hole assembly.However, the drilling machine still needs the ability to deploy andretrieve the individual components of the bottom hole assembly. In someembodiments, components are automatically retrieved by a carousel,deployed, and made up over the hole when running in the hole. Theprocess may be reversed when tripping out of the hole. Alternatively,components may be racked horizontally on the drilling machine. Thecomponents may be maneuvered with automatic pipe arms.

The drilling machine may employ a split injector system. When coiledtubing operations are halted, the two sides of the injector may beremotely unlatched and retracted to allow for over hole access.

In some embodiments that use coiled tubing, a bottom hole assemblyhandling rig is used to make up and deploy the bottom hole assembly inthe well conductor of a well to be drilled to total depth. The drillingmachine may leave the current bottom hole assembly in the well afterreaching total depth and prior to moving to the next well. Afterlatching on to the bottom hole assembly in the follow up well, thebottom hole assembly handling rig may pull the bottom hole assembly fromthe previous well and prepare it for the next well in sequence. The mastfor the bottom hole assembly handling rig may be a very simplearrangement supporting a sandline for bottom hole assembly handling.

A reel used by the drilling machine may have 500-1000 m of pipe. Toincrease the number of cycles the coiled tubing may be used, the reelmay have a large diameter and be relatively narrow. In some embodiments,the coiled tubing reel is the wellhead. Having the wellhead and the reelas one unit eliminates the additional handling of a separate wellheadand an empty reel.

Wellbores may be formed in the ground using any desired method.Wellbores may be drilled, impacted, and/or vibrated in the ground. Insome embodiments, wellbores are formed using reverse circulationdrilling. Reverse circulation drilling may minimize formation damage dueto contact with drilling muds and cuttings. Reverse circulation drillingmay inhibit contamination of cuttings so that recovered cuttings can beused as a substitute for coring. Reverse circulation drilling maysignificantly reduce the volume of drilling fluid used to form awellbore. Reverse circulation drilling enables fast penetration ratesand the use of low density drilling fluid. The drilling fluid may be,for example, air, mist, water, brine, or drilling mud. The reduction involume of drilling fluid may significantly reduce drilling costs.Formation water production is reduced when using reverse circulationdrilling. Reverse circulation drilling permits use of air drillingwithout resulting in excessive air pockets being left in the formation.Prevention of air pockets in the formation during formation of wellboresis desirable, especially if the wellbores are to be used as freeze wellsfor forming a barrier around a treatment area.

Reverse circulation drilling systems may include components to enabledirectional drilling. For example, steerable motors, bent subs foraltering the direction of the borehole, or autonomous drilling packagescould be included.

Reverse circulation drilling enables fast penetration rates and the useof low density drilling fluid such as air or mist. When tri-cone rockbits are used, a skirted rock bit assembly replaces the conventionaltri-cone bit. The skirt directs the drilling fluid from the pipe-in-pipedrill rod annulus to the outside portion of the hole being drilled. Asthe cuttings are generated by the action of the rotating drill bit, thecuttings mix with the drilling fluid, pass through a hole in the centerof the bit and are carried out of the hole through the center of thedrill rods. When a non-skirted drill bit is used, a reverse-circulationcrossover is installed between the standard bit and the drill rods. Thecrossover redirects the drilling fluid from the pipe-in-pipe drill rodannulus to the inside of the drill string about a meter above the bit.The drilling fluid passes through the bit jets, mixes with the cuttings,and returns up the drill string. At the crossover, the fluid/cuttingsmixture enters the drill string and continues to the surface inside theinner tube of the drill rod.

FIG. 11 depicts a schematic drawing of a reverse-circulatingpolycrystalline diamond compact drill bit design. Thereverse-circulating polycrystalline diamond compact (RC—PDC) drill bitdesign eliminates the crossover. RC—PDC bit 364 may include skirt 366that directs the drilling fluid from pipe-in-pipe drill rod annulus 368to bottom portion 370 of the wellbore being formed. In bottom portion370, the drilling fluid mixes with the cuttings generated by cutters 372of the RC—PDC bit. The drilling fluid and cuttings pass through opening374 in the center of RC—PDC bit 364 and are carried out of the wellborethrough drill rod center 376.

In some embodiments, the cuttings generated during drilling are milledand used as a filler material in a slurry used for forming a grout wall.Cuttings that contain hydrocarbon material may be retorted to extractthe hydrocarbons. Retorting the cuttings may be environmentallybeneficial because the reinjected cuttings are free of organic material.Recovering the hydrocarbons may offset a portion of the milling cost.

When drilling a wellbore, a magnet or magnets may be inserted into afirst opening to provide a magnetic field used to guide a drillingmechanism that forms an adjacent opening or adjacent openings. Themagnetic field may be detected by a 3-axis fluxgate magnetometer in theopening being drilled. A control system may use information detected bythe magnetometer to determine and implement operation parameters neededto form an opening that is a selected distance away from the firstopening (within desired tolerances).

Various types of wellbores may be formed using magnetic tracking. Forexample, wellbores formed by magnetic tracking may be used for in situconversion processes, for steam assisted gravity drainage processes, forthe formation of perimeter barriers or frozen barriers, and/or for soilremediation processes. Magnetic tracking may be used to form wellboresfor processes that require relatively small tolerances or variations indistances between adjacent wellbores. For example, vertical and/orhorizontally positioned heater wells and/or production wells may need tobe positioned parallel to each other with relatively little or novariance in parallel alignment to allow for substantially uniformheating and/or production from the treatment area in the formation.Also, freeze wells need to be positioned parallel to each other withrelatively little or no variance in parallel alignment to allowformation of overlapping cold zones that will result in a solid frozenbarrier around the treatment area.

In certain embodiments, a magnetic string is placed in a vertical well.The magnetic string in the vertical well is used to guide the drillingof a horizontal well such that the horizontal well connects to thevertical well at a desired location, passes the vertical well at aselected distance relative to the vertical well at a selected depth inthe formation, or stops a selected distance away from the vertical well.In some embodiments, the magnetic string is placed in a horizontal well.The magnetic string in the horizontal well is used to guide the drillingof a vertical well such that the vertical well connects to thehorizontal well at a desired location, passes the horizontal well at aselected distance relative to the horizontal well, or stops at aselected distance away from the horizontal well.

Analytical equations may be used to determine the spacing betweenadjacent wellbores using measurements of magnetic field strengths. Themagnetic field from a first wellbore may be measured by a magnetometerin a second wellbore. Analysis of the magnetic field strengths usingderivations of analytical equations may determine the coordinates of thesecond wellbore relative to the first wellbore.

FIG. 12 depicts a schematic representation of an embodiment of amagnetostatic drilling operation to form an opening that is a desireddistance (for example, a desired substantially parallel distance) awayfrom a drilled opening. In some embodiments, the magnetostatic drillingoperation forms the opening parallel to the drilled opening. Opening 378may be formed in hydrocarbon layer 380. Opening 378 may be used for anytype of application, including but not limited to, barrier formation,soil remediation, solution mining, steam-assisted gravity drainage(SAGD), and/or in situ conversion. A portion of opening 378 may beoriented substantially horizontally in hydrocarbon layer 380. Forexample, opening 378 may be formed substantially parallel to a boundary(for example, the surface or a boundary between hydrocarbon layer 380and overburden 382) of the formation. Opening 378 may be formed in otherorientations in hydrocarbon layer 380 depending on, for example, adesired use of the opening, formation depth, formation type, or otherfactors. Opening 378 may include casing 384. In certain embodiments,opening 378 is an open (or uncased) wellbore. In some embodiments,magnetic string 386 is inserted into opening 378. Magnetic string 386may be unwound from a reel into opening 378. In an embodiment, magneticstring 386 includes one or more magnet segments 388.

Magnet segments 388 may include one or more movable magnets that aremagnetizable and demagnetizable using a magnetic coil. Magnetic coil 390is located at or near the surface of the formation. Magnetic coil 390 isused to magnetize and demagnetize magnetic string 386. In certainembodiments, magnetic string 386 is magnetized by magnetic coil 390 asthe string is placed into opening 378. In an embodiment, as magneticstring 386 is removed from opening 378, magnetic coil 390 demagnetizesthe magnetic string. Demagnetizing magnetic string 386 as the magneticstring is removed makes the magnetic string safer and more efficient totransport (for example, shipping to another location or moving toanother location or opening in the formation).

In other embodiments, magnetic string 386 includes one or more movablepermanent longitudinal magnets. A movable permanent longitudinal magnetmay have a north pole and a south pole. Magnetic string 386 may have alongitudinal axis that is substantially parallel (for example, withinabout 5%, within about 10%, or within about 15% of parallel) or coaxialwith a longitudinal axis of opening 378.

Magnetic strings may be moved (for example, pushed and/or pulled)through an opening using a variety of methods. In an embodiment, amagnetic string may be coupled to a drill string and moved through theopening as the drill string moves through the opening. Alternatively,magnetic strings may be installed using coiled tubing rigs. Someembodiments may include coupling a magnetic string to a tractor systemthat moves through the opening. Commercially available tractor systemsfrom Welltec Well Technologies (Denmark) or Schlumberger Technology Co.(Houston, Tex., U.S.A.) may be used. In certain embodiments, magneticstrings are pulled by cable or wireline from either end portion of theopening. In an embodiment, magnetic strings are pumped through theopening using air and/or water. For example, a pig may be moved throughthe opening by pumping air and/or water through the opening and themagnetic string may be coupled to the pig.

In some embodiments, casing 384 is a conduit. Casing 384 may be made ofa material that is not significantly influenced by a magnetic field (forexample, non-magnetic alloy such as non-magnetic stainless steel (forexample, 304, 310, or 316 stainless steel), reinforced polymer pipe, orbrass tubing). The casing may be a conduit of a conductor-in-conduitheater, a perforated liner, or a perforated casing. If the casing is notsignificantly influenced by a magnetic field, then the magnetic fluxwill not be shielded.

In some embodiments, the casing is made of a ferromagnetic material (forexample, carbon steel). Ferromagnetic material may have a magneticpermeability greater than about 1. The use of ferromagnetic material mayweaken the strength of the magnetic field to be detected by drillingapparatus 392 in adjacent opening 394. For example, carbon steel mayweaken the magnetic field strength outside of the casing (for example,by a factor of 3 depending on the diameter, wall thickness, and/ormagnetic permeability of the casing). Measurements may be made with themagnetic string inside the carbon steel casing (or other magneticallyshielding casing) at the surface to determine the effective polestrengths of the magnetic string when shielded by the ferromagneticmaterial. Measurements of the magnetic field produced by magnetic string386 in adjacent opening 394 may be used to determine the relativecoordinates of adjacent opening 394 to opening 378.

In some embodiments, drilling apparatus 392 includes a magnetic guidancesensor probe. The magnetic guidance sensor probe may contain a 3-axisfluxgate magnetometer and a 3-axis inclinometer. The inclinometer istypically used to determine the rotation of the sensor probe relative toEarth's gravitational field (the “toolface angle”). A general magneticguidance sensor probe may be obtained from Tensor Energy Products (RoundRock, Tex., U.S.A.). The magnetic guidance sensor may be placed insidethe drilling string coupled to a drill bit. In certain embodiments, themagnetic guidance sensor probe is located inside the drilling string ofa river crossing rig.

Magnet segments 388 may be placed in conduit 396. Conduit 396 may be athreaded tubular or seamless tubular. Conduit 396 may be formed bycoupling one or more sections 398. Sections 398 may include non-magneticmaterials such as, but not limited to, stainless steel. In certainembodiments, conduit 396 is formed by coupling several threaded tubularsections. Sections 398 may have any length desired (for example, thesections may have a standard length for threaded tubulars). Sections 398may have a length chosen to produce magnetic fields with selecteddistances between junctions of opposing poles in magnetic string 386.The distance between junctions of opposing poles may determine thesensitivity of a magnetic steering method, which corresponds to theaccuracy in determining the distance between adjacent wellbores.Typically, the distance between junctions of opposing poles is chosen tobe on the same scale as the distance between adjacent wellbores (forexample, the distance between junctions may be in a range of about 0.5 mto about 750 m, of about 1 m to about 500 m or, of about 2 m to about200 m).

Conduit 396 may be a threaded stainless steel tubular. In an embodiment,conduit 396 is 2½ inch Schedule 40, 304 stainless steel tubular formedfrom 20 ft long sections 398. With 20 ft long sections. 398, thedistance between opposing poles will be about 20 ft. In someembodiments, sections 398 may be coupled as the conduit is formed and/orinserted into opening 378. Conduit 396 may have a length between about375 ft and about 525 ft. Shorter or longer lengths of conduit 396 may beused depending on a desired application of the magnetic string.

In an embodiment, sections 398 of conduit 396 includes two magnetsegments 388. In an embodiment, sections 398 of conduit 396 include onlyone magnet segment. In some embodiments, sections 398 of conduit 396include more than two magnet segments. Magnet segments 388 may bearranged in sections 398 such that adjacent magnet segments haveopposing polarities at the junction of the segments, as shown in FIG.12. In an embodiment, one section 398 includes two magnet segments 388of opposing polarities. The polarity between adjacent sections 398 maybe arranged such that the sections have attracting polarities, as shownin FIG. 12. Arranging the opposing poles approximate the center of eachsection may make assembly of the magnet segments in each sectionrelatively easy. In an embodiment, the approximate centers of adjacentsections 398 have opposite poles. For example, the approximate center ofone section may have north poles and the adjacent section (or sectionson each end of the one section) may have south poles as shown in FIG.12.

Fasteners 400 may be placed at the ends of sections 398 to hold magnetsegments 388 in the sections. Fasteners 400 may include, but are notlimited to, pins, bolts, or screws. Fasteners 400 may be made ofnon-magnetic materials. In some embodiments, ends of sections 398 areclosed off (for example, end caps are placed on the ends) to enclosemagnet segments 388 in the sections. In certain embodiments, fasteners400 are also placed at junctions of opposing poles of adjacent magnetsegments 388 to inhibit the adjacent segments from moving apart.

FIG. 13 depicts an embodiment of section 398 with two magnet segments388 with opposing poles. Magnet segments 388 may include one or moremagnets 402 coupled to form a single magnet segment. Magnet segments 388and/or magnets 402 may be positioned in a linear array. Magnets 402 maybe Alnico magnets or other types of magnets (such as neodymium iron orsamarium cobalt) with sufficient magnetic strength to produce a magneticfield that can be detected in a nearby wellbore. Alnico magnets are madeprimarily from alloys of aluminum, nickel, and cobalt and may beobtained, for example, from Adams Magnetic Products Co. (Elmhurst, Ill.,U.S.A.). In certain embodiment, using permanent magnets in magnetsegments 388 may reduce the infrastructure associated with magnetictracking compared to using inductive coils or magnetic field producingwires since there is no need to provide electrical current. In anembodiment, magnets 402 are Alnico magnets about 6 cm in diameter andabout 15 cm in length. Assembling a magnet segment from severalindividual magnets increases the strength of the magnetic field producedby the magnet segment. Increasing the strength of the magnetic fieldsproduced by magnet segments may advantageously increase the maximumdistance for detecting the magnetic fields. The pole strength of amagnet segment may be between about 100 Gauss and about 2000 Gauss, orbetween about 1000 Gauss and about 2000 Gauss. In an embodiment, thepole strength of the magnet segment is 1500 Gauss. Magnets 402 may becoupled with attracting poles coupled such that magnet segment 388 isformed with a south pole at one end and a north pole at a second end. Inone embodiment, 40 magnets 402 of about 15 cm in length are coupled toform magnet segment 388 of about 6 m in length. Opposing poles of magnetsegments 388 may be aligned proximate the center of section 398 as shownin FIGS. 12 and 13. Magnet segments 388 may be placed in section 398 andthe magnet segments may be held in the section with fasteners 400. Oneor more sections 398 may be coupled as shown in FIG. 12 to form amagnetic string. In certain embodiments, un-magnetized magnet segments388 may be coupled together inside sections 398. Sections 398 may bemagnetized with a magnetizing coil after magnet segments 388 have beenassembled together into the sections.

FIG. 14 depicts a schematic of an embodiment of a portion of magneticstring 386. Magnet segments 388 may be positioned such that adjacentsegments have opposing poles. In some embodiments, force is applied tominimize distance 404 between magnet segments 388. Additional segmentsmay be added to increase the length of magnetic string 386. Magnetsegments 388 may be located in sections 398, as shown in FIG. 12.Magnetic strings may be coiled after assembling. Installation of themagnetic string may include uncoiling the magnetic string. Coiling anduncoiling of the magnetic string may also be used to change position ofthe magnetic string relative to a sensor in a nearby wellbore, forexample, drilling apparatus 392 in opening 394, as shown in FIG. 12.

Magnetic strings may include multiple south-south and north-northopposing pole junctions. As shown in FIG. 14, the multiple opposing polejunctions may induce a series of magnetic fields 406. Alternating thepolarity of portions in the magnetic string may provide a sinusoidalvariation of the magnetic field along the length of the magnetic string.The magnetic field variations may allow for control of the desiredspacing between drilled wellbores. A series of magnetic fields 406 maybe detected at greater distances than individual magnetic fields.Increasing the distance between opposing pole junctions in the magneticstring may increase the radial distance at which a magnetometer candetect the magnetic field. In some embodiments, the distance betweenopposing pole junctions in the magnetic string is varied. For example,more magnets may be used in portions proximate Earth's surface than inportions positioned deeper in the formation.

Some wellbores formed in the formation may be used to facilitateformation of a perimeter barrier around a treatment area. Heat sourcesin the treatment area may heat hydrocarbons in the formation within thetreatment area. The perimeter barrier may be, but is not limited to, alow temperature or frozen barrier formed by freeze wells, dewateringwells, a grout wall formed in the formation, a sulfur cement barrier, abarrier formed by a gel produced in the formation, a barrier formed byprecipitation of salts in the formation, a barrier formed by apolymerization reaction in the formation, and/or sheets driven into theformation. Heat sources, production wells, injection wells, dewateringwells, and/or monitoring wells may be installed in the treatment areadefined by the barrier prior to, simultaneously with, or afterinstallation of the barrier.

A low temperature zone around at least a portion of a treatment area maybe formed by freeze wells. In an embodiment, refrigerant is circulatedthrough freeze wells to form low temperature zones around each freezewell. The freeze wells are placed in the formation so that the lowtemperature zones overlap and form a low temperature zone around thetreatment area. The low temperature zone established by freeze wells ismaintained below the freezing temperature of aqueous fluid in theformation. Aqueous fluid entering the low temperature zone freezes andforms the frozen barrier. In other embodiments, the freeze barrier isformed by batch operated freeze wells. A cold fluid, such as liquidnitrogen, is introduced into the freeze wells to form low temperaturezones around the freeze wells. The fluid is replenished as needed.

In some embodiments, two or more rows of freeze wells are located aboutall or a portion of the perimeter of the treatment area to form a thickinterconnected low temperature zone. Thick low temperature zones may beformed adjacent to areas in the formation where there is a high flowrate of aqueous fluid in the formation. The thick barrier may ensurethat breakthrough of the frozen barrier established by the freeze wellsdoes not occur.

Vertically positioned freeze wells and/or horizontally positioned freezewells may be positioned around sides of the treatment area. If the upperlayer (the overburden) or the lower layer (the underburden) of theformation is likely to allow fluid flow into the treatment area or outof the treatment area, horizontally positioned freeze wells may be usedto form an upper and/or a lower barrier for the treatment area. In someembodiments, an upper barrier and/or a lower barrier may not benecessary if the upper layer and/or the lower layer are at leastsubstantially impermeable. If the upper freeze barrier is formed,portions of heat sources, production wells, injection wells, and/ordewatering wells that pass through the low temperature zone created bythe freeze wells forming the upper freeze barrier wells may be insulatedand/or heat traced so that the low temperature zone does not adverselyaffect the functioning of the heat sources, production wells, injectionwells and/or dewatering wells passing through the low temperature zone.

Spacing between adjacent freeze wells may be a function of a number ofdifferent factors. The factors may include, but are not limited to,physical properties of formation material, type of refrigeration system,coldness and thermal properties of the refrigerant, flow rate ofmaterial into or out of the treatment area, time for forming the lowtemperature zone, and economic considerations. Consolidated or partiallyconsolidated formation material may allow for a large separationdistance between freeze wells. A separation distance between freezewells in consolidated or partially consolidated formation material maybe from about 3 m to about 20 m, about 4 m to about 15 m, or about 5 mto about 10 m. In an embodiment, the spacing between adjacent freezewells is about 5 m. Spacing between freeze wells in unconsolidated orsubstantially unconsolidated formation material, such as in tar sand,may need to be smaller than spacing in consolidated formation material.A separation distance between freeze wells in unconsolidated materialmay be from about 1 m to about 5 m.

Freeze wells may be placed in the formation so that there is minimaldeviation in orientation of one freeze well relative to an adjacentfreeze well. Excessive deviation may create a large separation distancebetween adjacent freeze wells that may not permit formation of aninterconnected low temperature zone between the adjacent freeze wells.Factors that influence the manner in which freeze wells are insertedinto the ground include, but are not limited to, freeze well insertiontime, depth that the freeze wells are to be inserted, formationproperties, desired well orientation, and economics.

Relatively low depth wellbores for freeze wells may be impacted and/orvibrationally inserted into some formations. Wellbores for freeze wellsmay be impacted and/or vibrationally inserted into formations to depthsfrom about 1 m to about 100 m without excessive deviation in orientationof freeze wells relative to adjacent freeze wells in some types offormations.

Wellbores for freeze wells placed deep in the formation, or wellboresfor freeze wells placed in formations with layers that are difficult toimpact or vibrate a well through, may be placed in the formation bydirectional drilling and/or geosteering. Acoustic signals, electricalsignals, magnetic signals, and/or other signals produced in a firstwellbore may be used to guide directionally drilling of adjacentwellbores so that desired spacing between adjacent wells is maintained.Tight control of the spacing between wellbores for freeze wells is animportant factor in minimizing the time for completion of barrierformation.

After formation of the wellbore for the freeze well, the wellbore may bebackflushed with water adjacent to the part of the formation that is tobe reduced in temperature to form a portion of the freeze barrier. Thewater may displace drilling fluid remaining in the wellbore. The watermay displace indigenous gas in cavities adjacent to the formation. Insome embodiments, the wellbore is filled with water from a conduit up tothe level of the overburden. In some embodiments, the wellbore isbackflushed with water in sections. The wellbore maybe treated insections having lengths of about 6 m, 10 m, 14 m, 17 m, or greater.Pressure of the water in the wellbore is maintained below the fracturepressure of the formation. In some embodiments, the water, or a portionof the water is removed from the wellbore, and a freeze well is placedin the formation.

FIG. 15 depicts an embodiment of freeze well 408. Freeze well 408 mayinclude canister 410, inlet conduit 412, spacers 414, and wellcap 416.Spacers 414 may position inlet conduit 412 in canister 410 so that anannular space is formed between the canister and the conduit. Spacers414 may promote turbulent flow of refrigerant in the annular spacebetween inlet conduit 412 and canister 410, but the spacers may alsocause a significant fluid pressure drop. Turbulent fluid flow in theannular space may be promoted by roughening the inner surface ofcanister 410, by roughening the outer surface of inlet conduit 412,and/or by having a small cross-sectional area annular space that allowsfor high refrigerant velocity in the annular space. In some embodiments,spacers are not used. Wellhead 418 may suspend canister 410 in wellbore420.

Formation refrigerant may flow through cold side conduit 417 from arefrigeration unit to inlet conduit 412 of freeze well 408. Theformation refrigerant may flow through an annular space between inletconduit 412 and canister 410 to warm side conduit 419. Heat may transferfrom the formation to canister 410 and from the canister to theformation refrigerant in the annular space. Inlet conduit 412 may beinsulated to inhibit heat transfer to the formation refrigerant duringpassage of the formation refrigerant into freeze well 408. In anembodiment, inlet conduit 412 is a high density polyethylene tube. Atcold temperatures, some polymers may exhibit a large amount of thermalcontraction. For example, a 260 m initial length of polyethylene conduitsubjected to a temperature of about −25° C. may contract by 6 m or more.If a high density polyethylene conduit, or other polymer conduit, isused, the large thermal contraction of the material must be taken intoaccount in determining the final depth of the freeze well. For example,the freeze well may be drilled deeper than needed, and the conduit maybe allowed to shrink back during use. In some embodiments, inlet conduit412 is an insulated metal tube. In some embodiments, the insulation maybe a polymer coating, such as, but not limited to, polyvinylchloride,high density polyethylene, and/or polystyrene.

Freeze well 408 may be introduced into the formation using a coiledtubing rig. In an embodiment, canister 410 and inlet conduit 412 arewound on a single reel. The coiled tubing rig introduces the canisterand inlet conduit 412 into the formation. In an embodiment, canister 410is wound on a first reel and inlet conduit 412 is wound on a secondreel. The coiled tubing rig introduces canister 410 into the formation.Then, the coiled tubing rig is used to introduce inlet conduit 412 intothe canister. In other embodiments, freeze well is assembled in sectionsat the wellbore site and introduced into the formation.

An insulated section of freeze well 408 may be placed adjacent tooverburden 382. An uninsulated section of freeze well 408 may be placedadjacent to layer or layers 380 where a low temperature zone is to beformed. In some embodiments, uninsulated sections of the freeze wellsmay be positioned adjacent only to aquifers or other permeable portionsof the formation that would allow fluid to flow into or out of thetreatment area. Portions of the formation where uninsulated sections ofthe freeze wells are to be placed may be determined using analysis ofcores and/or logging techniques.

Various types of refrigeration systems may be used to form a lowtemperature zone. Determination of an appropriate refrigeration systemmay be based on many factors, including, but not limited to: a type offreeze well; a distance between adjacent freeze wells; a refrigerant; atime frame in which to form a low temperature zone; a depth of the lowtemperature zone; a temperature differential to which the refrigerantwill be subjected; one or more chemical and/or physical properties ofthe refrigerant; one or more environmental concerns related to potentialrefrigerant releases, leaks or spills; one or more economic factors;water flow in the formation; composition and/or properties of formationwater including the salinity of the formation water; and one or moreproperties of the formation such as thermal conductivity, thermaldiffusivity, and heat capacity.

A circulated fluid refrigeration system may utilize a liquid refrigerant(formation refrigerant) that is circulated through freeze wells. Some ofthe desired properties for the formation refrigerant are: low workingtemperature, low viscosity at and near the working temperature, highdensity, high specific heat capacity, high thermal conductivity, lowcost, low corrosiveness, and low toxicity. A low working temperature ofthe formation refrigerant allows a large low temperature zone to beestablished around a freeze well. The low working temperature offormation refrigerant should be about −20° C. or lower. Formationrefrigerants having low working temperatures of at least −60° C. mayinclude aqua ammonia, potassium formate solutions such as Dynalene®HC-50 (Dynalene® Heat Transfer Fluids (Whitehall, Pa., U.S.A.)) orFREEZIUM® (Kemira Chemicals (Helsinki, Finland)); silicone heat transferfluids such as Syltherm XLT® (Dow Corning Corporation (Midland, Mich.,U.S.A.); hydrocarbon refrigerants such as propylene; andchlorofluorocarbons such as R-22. Aqua ammonia is a solution of ammoniaand water with a weight percent of ammonia between about 20% and about40%. Aqua ammonia has several properties and characteristics that makeuse of aqua ammonia as the formation refrigerant desirable. Suchproperties and characteristics include, but are not limited to, a verylow freezing point, a low viscosity, ready availability, and low cost.

Formation refrigerant that is capable of being chilled below a freezingtemperature of aqueous formation fluid may be used to form the lowtemperature zone around the treatment area. The following equation (theSanger equation) may be used to model the time t₁ needed to form afrozen barrier of radius R around a freeze well having a surfacetemperature of T_(s):

$\begin{matrix}{t_{1} = {\frac{R^{2}L_{1}}{4k_{f}v_{s}}\left( {{2\ln\frac{R}{r_{o}}} - 1 + \frac{c_{vf}v_{s}}{L_{1}}} \right)}} & (1)\end{matrix}$

-   -   in which:

$\begin{matrix}{L_{1} = {L\;\frac{a_{r}^{2} - 1}{2\ln\; a_{r}}c_{vu}v_{o}}} \\{a_{r} = {\frac{R_{A}}{R}.}}\end{matrix}$In these equations, k_(f) is the thermal conductivity of the frozenmaterial; c_(vf) and c_(vu) are the volumetric heat capacity of thefrozen and unfrozen material, respectively; r_(o) is the radius of thefreeze well; ν_(s) is the temperature difference between the freeze wellsurface temperature T_(s) and the freezing point of water T_(o); ν_(o)is the temperature difference between the ambient ground temperatureT_(g) and the freezing point of water T_(o); L is the volumetric latentheat of freezing of the formation; R is the radius at thefrozen-unfrozen interface; and R_(A) is a radius at which there is noinfluence from the refrigeration pipe. The Sanger equation may provide aconservative estimate of the time needed to form a frozen barrier ofradius R because the equation does not take into considerationsuperposition of cooling from other freeze wells. The temperature of theformation refrigerant is an adjustable variable that may significantlyaffect the spacing between freeze wells.

EQN. 1 implies that a large low temperature zone may be formed by usinga refrigerant having an initial temperature that is very low. The use offormation refrigerant having an initial cold temperature of about −30°C. or lower is desirable. Formation refrigerants having initialtemperatures warmer than about −30° C. may also be used, but suchformation refrigerants require longer times for the low temperaturezones produced by individual freeze wells to connect. In addition, suchformation refrigerants may require the use of closer freeze wellspacings and/or more freeze wells.

The physical properties of the material used to construct the freezewells may be a factor in the determination of the coldest temperature ofthe formation refrigerant used to form the low temperature zone aroundthe treatment area. Carbon steel may be used as a construction materialof freeze wells. ASTM A333 grade 6 steel alloys and ASTM A333 grade 3steel alloys may be used for low temperature applications. ASTM A333grade 6 steel alloys typically contain little or no nickel and have alow working temperature limit of about −50° C. ASTM A333 grade 3 steelalloys typically contain nickel and have a much colder low workingtemperature limit. The nickel in the ASTM A333 grade 3 alloy addsductility at cold temperatures, but also significantly raises the costof the metal. In some embodiments, the coldest temperature of therefrigerant is from about −35° C. to about −55° C., from about −38° C.to about 47° C., or from about 40° C. to about 45° C. to allow for theuse of ASTM A333 grade 6 steel alloys for construction of canisters forfreeze wells. Stainless steels, such as 304 stainless steel, may be usedto form freeze wells, but the cost of stainless steel is typically muchmore than the cost of ASTM A333 grade 6 steel alloy.

In some embodiments, the metal used to form the canisters of the freezewells may be provided as pipe. In some embodiments, the metal used toform the canisters of the freeze wells may be provided in sheet form.The sheet metal may be longitudinally welded to form pipe and/or coiledtubing. Forming the canisters from sheet metal may improve the economicsof the system by allowing for coiled tubing insulation and by reducingthe equipment and manpower needed to form and install the canistersusing pipe.

A refrigeration unit may be used to reduce the temperature of formationrefrigerant to the low working temperature. In some embodiments, therefrigeration unit may utilize an ammonia vaporization cycle.Refrigeration units are available from Cool Man Inc. (Milwaukee, Wis.,U.S.A.), Gartner Refrigeration & Manufacturing (Minneapolis, Minn.,U.S.A.), and other suppliers. In some embodiments, a cascadingrefrigeration system may be utilized with a first stage of ammonia and asecond stage of carbon dioxide. The circulating refrigerant through thefreeze wells may be 30% by weight ammonia in water (aqua ammonia).Alternatively, a single stage carbon dioxide refrigeration system may beused.

FIG. 16 depicts an embodiment of refrigeration system 422 used to coolformation refrigerant that forms a low temperature zone around treatmentarea 424. Refrigeration system 422 may include a high stagerefrigeration system and a low stage refrigeration system arranged in acascade relationship. The high stage refrigeration system and the lowstage refrigeration system may utilize conventional vapor compressionrefrigeration cycles.

The high stage refrigeration system includes compressor 426, condenser428, expansion valve 430, and heat exchanger 432. In some embodiments,the high stage refrigeration system uses ammonia as the refrigerant. Thelow stage refrigeration system includes compressor 434, heat exchanger432, expansion valve 436, and heat exchanger 438. In some embodiments,the low stage refrigeration system uses carbon dioxide as therefrigerant. High stage refrigerant from high stage expansion valve 430cools low stage refrigerant exiting low stage compressor 434 in heatexchanger 432.

Low stage refrigerant exiting low stage expansion valve 436 is used tocool formation refrigerant in heat exchanger 438. The formationrefrigerant passes from heat exchanger 438 to storage vessel 440. Pump442 transports formation refrigerant from storage vessel 440 to freezewells 408 in formation 444. Refrigeration system 422 is operated so thatthe formation refrigerant from pump 442 is at the desired temperature.The desired temperature may be in the range from about −35° C. to about−55° C.

Formation refrigerant passes from the freeze wells 408 to storage vessel446. Pump 448 is used to transport the formation refrigerant fromstorage vessel 446 to heat exchanger 438. In some embodiments, storagevessel 440 and storage vessel 446 are a single tank with a warm side forformation refrigerant returning from the freeze wells, and a cold sidefor formation refrigerant from heat exchanger 438.

In some embodiments, a double barrier system is used to isolate atreatment area. The double barrier system may be formed with a firstbarrier and a second barrier. The first barrier may be formed around atleast a portion of the treatment area to inhibit fluid from entering orexiting the treatment area. The second barrier may be formed around atleast a portion of the first barrier to isolate an inter-barrier zonebetween the first barrier and the second barrier. The double barriersystem may allow greater project depths than a single barrier system.Greater depths are possible with the double barrier system because thestepped differential pressures across the first barrier and the secondbarrier is less than the differential pressure across a single barrier.The smaller differential pressures across the first barrier and thesecond barrier make a breach of the double barrier system less likely tooccur at depth for the double barrier system as compared to the singlebarrier system.

The double barrier system reduces the probability that a barrier breachwill affect the treatment area or the formation on the outside of thedouble barrier. That is, the probability that the location and/or timeof occurrence of the breach in the first barrier will coincide with thelocation and/or time of occurrence of the breach in the second barrieris low, especially if the distance between the first barrier and thesecond barrier is relatively large (for example, greater than about 15m). Having a double barrier may reduce or eliminate influx of fluid intothe treatment area following a breach of the first barrier or the secondbarrier. The treatment area may not be affected if the second barrierbreaches. If the first barrier breaches, only a portion of the fluid inthe inter-barrier zone is able to enter the contained zone. Also, fluidfrom the contained zone will not pass the second barrier. Recovery froma breach of a barrier of the double barrier system may require less timeand fewer resources than recovery from a breach of a single barriersystem. For example, reheating a treatment area zone following a breachof a double barrier system may require less energy than reheating asimilarly sized treatment area zone following a breach of a singlebarrier system.

The first barrier and the second barrier may be the same type of barrieror different types of barriers. In some embodiments, the first barrierand the second barrier are formed by freeze wells. In some embodiments,the first barrier is formed by freeze wells, and the second barrier is agrout wall. The grout wall may be formed of cement, sulfur, sulfurcement, or combinations thereof. In some embodiments, a portion of thefirst barrier and/or a portion of the second barrier is a naturalbarrier, such as an impermeable rock formation.

FIG. 17 depicts an embodiment of double barrier system 450. Theperimeter of treatment area 452 may be surrounded by first barrier 454.First barrier 454 may be surrounded by second barrier 456. Inter-barrierzones 458 may be isolated between first barrier 454, second barrier 456and partitions 460. Creating sections with partitions 460 between firstbarrier 454 and second barrier 456 limits the amount of fluid held inindividual inter-barrier zones 458. Partitions 460 may strengthen doublebarrier system 450. In some embodiments, the double barrier system maynot include partitions.

The inter-barrier zone may have a thickness from about 1 m to about 300m. In some embodiments, the thickness of the inter-barrier zone is fromabout 10 m to about 100 m, or from about 20 m to about 50 m.

Pumping/monitor wells 462 may be positioned in contained zone 452,inter-barrier zones 458, and/or outer zone 464 outside of second barrier456. Pumping/monitor wells 462 allow for removal of fluid from treatmentarea 452, inter-barrier zones 458, or outer zone 464. Pumping/monitorwells 462 also allow for monitoring of fluid levels in treatment area452, inter-barrier zones 458, and outer zone 464.

In some embodiments, a portion of treatment area 452 is heated by heatsources. The closest heat sources to first barrier 454 may be installeda desired distance away from the first barrier. In some embodiments, thedesired distance between the closest heat sources and first barrier 454is in a range between about 5 m and about 300 m, between about 10 m andabout 200 m, or between about 15 m and about 50 m. For example, thedesired distance between the closest heat sources and first barrier 454may be about 40 m.

FIG. 18 depicts a cross-sectional view of double barrier system 450 usedto isolate treatment area 452 in the formation. The formation mayinclude one or more fluid bearing zones 466 and one or more impermeablezones 468. First barrier 454 may at least partially surround treatmentarea 452. Second barrier 456 may at least partially surround firstbarrier 454. In some embodiments, impermeable zones 468 are locatedabove and/or below treatment area 452. Thus, treatment area 452 issealed around the sides and from the top and bottom. In someembodiments, one or more paths 470 are formed to allow communicationbetween two or more fluid bearing zones 466 in treatment area 452. Fluidin treatment area 452 may be pumped from the zone. Fluid ininter-barrier zone 458 and fluid in outer zone 464 is inhibited fromreaching the treatment area. During in situ conversion of hydrocarbonsin treatment area 452, formation fluid generated in the treatment areais inhibited from passing into inter-barrier zone 458 and outer zone464.

After sealing treatment area 452, fluid levels in a given fluid bearingzone 466 may be changed so that the fluid head in inter-barrier zone 458and the fluid head in outer zone 464 are different. The amount of fluidand/or the pressure of the fluid in individual fluid bearing zones 466may be adjusted after first barrier 454 and second barrier 456 areformed. The ability to maintain different amounts of fluid and/orpressure in fluid bearing zones 466 may indicate the formation andcompleteness of first barrier 454 and second barrier 456. Havingdifferent fluid head levels in treatment area 452, fluid bearing zones466 in inter-barrier zone 458, and in the fluid bearing zones in outerzone 464 allows for determination of the occurrence of a breach in firstbarrier 454 and/or second barrier 456. In some embodiments, thedifferential pressure across first barrier 454 and second barrier 456 isadjusted to reduce stresses applied to first barrier 454 and/or secondbarrier 456, or stresses on certain strata of the formation.

Some fluid bearing zones 466 may contain native fluid that is difficultto freeze because of a high salt content or compounds that reduce thefreezing point of the fluid. If first barrier 454 and/or second barrier456 are low temperature zones established by freeze wells, the nativefluid that is difficult to freeze may be removed from fluid bearingzones 466 in inter-barrier zone 458 through pumping/monitor wells 462.The native fluid is replaced with a fluid that the freeze wells are ableto more easily freeze.

In some embodiments, pumping/monitor wells 462 may be positioned intreatment area 452, inter-barrier zone 458, and/or outer zone 464.Pumping/monitor wells 462 may be used to test for freeze completion offrozen barriers and/or for pressure testing frozen barriers and/orstrata. Pumping/monitor wells 462 may be used to remove fluid and/or tomonitor fluid levels in treatment area 452, inter-barrier zone 458,and/or outer zone 464. Using pumping/monitor wells 462 to monitor fluidlevels in contained zone 452, inter-barrier zone 458, and/or outer zone464 may allow detection of a breach in first barrier 454 and/or secondbarrier 456. Pumping/monitor wells 462 allow pressure in treatment area452, each fluid bearing zone 466 in inter-barrier zone 458, and eachfluid bearing zone in outer zone 464 to be independently monitored sothat the occurrence and/or the location of a breach in first barrier 454and/or second barrier 456 can be determined.

In some embodiments, fluid pressure in inter-barrier zone 458 ismaintained greater than the fluid pressure in treatment area 452, andless than the fluid pressure in outer zone 464. If a breach of firstbarrier 454 occurs, fluid from inter-barrier zone 458 flows intotreatment area 452, resulting in a detectable fluid level drop in theinter-barrier zone. If a breach of second barrier 456 occurs, fluid fromthe outer zone flows into inter-barrier zone 458, resulting in adetectable fluid level rise in the inter-barrier zone.

A breach of first barrier 454 may allow fluid from inter-barrier zone458 to enter treatment area 452. FIG. 19 depicts breach 472 in firstbarrier 454 of double barrier containment system 450. Arrow 474indicates flow direction of fluid 476 from inter-barrier zone 458 totreatment area 452 through breach 472. The fluid level in fluid bearingzone 466 proximate breach 472 of inter-barrier zone 458 falls to theheight of the breach. Path 470 allows fluid 476 to flow from breach 472to the bottom of treatment area 452, increasing the fluid level in thebottom of the contained zone. The volume of fluid that flows intotreatment area 452 from inter-barrier zone 458 is typically smallcompared to the volume of the treatment area. The volume of fluid ableto flow into treatment area 452 from inter-barrier zone 458 is limitedbecause second barrier 456 inhibits recharge of fluid 476 into theaffected fluid bearing zone. In some embodiments, the fluid that enterstreatment area 452 may be pumped from the treatment area usingpumping/monitor wells 462 in the treatment area. In some embodiments,the fluid that enters treatment area 452 may be evaporated by heaters inthe treatment area that are part of the in situ conversion processsystem. The recovery time for the heated portion of treatment area 452from cooling caused by the introduction of fluid from inter-barrier zone458 is brief. The recovery time may be less than a month, less than aweek, or less than a day.

Pumping/monitor wells 462 in inter-barrier zone 458 may allow assessmentof the location of breach 472. When breach 472 initially forms, fluidflowing into treatment area 452 from fluid bearing zone 466 proximatethe breach creates a cone of depression in the fluid level of theaffected fluid bearing zone in inter-barrier zone 458. Time analysis offluid level data from pumping/monitor wells 462 in the same fluidbearing zone as breach 472 can be used to determine the general locationof the breach.

When breach 472 of first barrier 454 is detected, pumping/monitor wells462 located in the fluid bearing zone that allows fluid to flow intotreatment area 452 may be activated to pump fluid out of theinter-barrier zone. Pumping the fluid out of the inter-barrier zonereduces the amount of fluid 476 that can pass through breach 472 intotreatment area 452.

Breach 472 may be caused by ground shift. If first barrier 454 is a lowtemperature zone formed by freeze wells, the temperature of theformation at breach 472 in the first barrier is below the freezing pointof fluid 476 in inter-barrier zone 458. Passage of fluid 476 frominter-barrier zone 458 through breach 472 may result in freezing of thefluid in the breach and self-repair of first barrier 454.

A breach of the second barrier may allow fluid in the outer zone toenter the inter-barrier zone. The first barrier may inhibit fluidentering the inter-barrier zone from reaching the treatment area. FIG.20 depicts breach 472 in second barrier 456 of double barrier system450. Arrow 474 indicates flow direction of fluid 476 from outside ofsecond barrier 456 to inter-barrier zone 458 through breach 472. Asfluid 476 flows through breach 472 in second barrier 456, the fluidlevel in the portion of inter-barrier zone 458 proximate the breachrises from initial level 478 to a level that is equal to level 480 offluid in the same fluid bearing zone in outer zone 464. An increase offluid 476 in fluid bearing zone 466 may be detected by pumping/monitorwell 462 positioned in the fluid bearing zone proximate breach 472.

Breach 472 may be caused by ground shift. If second barrier 456 is a lowtemperature zone formed by freeze wells, the temperature of theformation at breach 472 in the second barrier is below the freezingpoint of fluid 476 entering from outer zone 464. Fluid from outer zone464 in breach 472 may freeze and self-repair second barrier 456.

First barrier and second barrier of the double barrier containmentsystem may be formed by freeze wells. In an embodiment, first barrier isformed first. The cooling load needed to maintain the first barrier issignificantly less than the cooling load needed to form the firstbarrier. After formation of the first barrier, the excess coolingcapacity that the refrigeration system used to form the first barriermay be used to form a portion of the second barrier. In someembodiments, the second barrier is formed first and the excess coolingcapacity that the refrigeration system used to form the second barrieris used to form a portion of the first barrier. After the first andsecond barriers are formed, excess cooling capacity supplied by therefrigeration system or refrigeration systems used to form the firstbarrier and the second barrier may be used to form a barrier or barriersaround the next contained zone that is to be processed by the in situconversion process.

Grout may be used in combination with freeze wells to provide a barrierfor the in situ conversion process. The grout fills cavities (vugs) inthe formation and reduces the permeability of the formation. Grout mayhave better thermal conductivity than gas and/or formation fluid thatfills cavities in the formation. Placing grout in the cavities may allowfor faster low temperature zone formation. The grout forms a perpetualbarrier in the formation that may strengthen the formation. The use ofgrout in unconsolidated or substantially unconsolidated formationmaterial may allow for larger well spacing than is possible without theuse of grout. The combination of grout and the low temperature zoneformed by freeze wells may constitute a double barrier for environmentalregulation purposes.

Grout may be introduced into the formation through freeze wellwellbores. The grout may be allowed to set. The integrity of the groutwall may be checked. The integrity of the grout wall may be checked bylogging techniques and/or by hydrostatic testing. If the permeability ofa grouted section is too high, additional grout may be introduced intothe formation through freeze well wellbores. After the permeability ofthe grouted section is sufficiently reduced, freeze wells may beinstalled in the freeze well wellbores.

Grout may be injected into the formation at a pressure that is high, butbelow the fracture pressure of the formation. In some embodiments,grouting is performed in 16 m increments in the freeze wellbore. Largeror smaller increments may be used if desired. In some embodiments, groutis only applied to certain portions of the formation. For example, groutmay be applied to the formation through the freeze wellbore onlyadjacent to aquifer zones and/or to relatively high permeability zones(for example, zones with a permeability greater than about 0.1 darcy).Applying grout to aquifers may inhibit migration of water from oneaquifer to a different aquifer when an established low temperature zonethaws.

Grout used in the formation may be any type of grout including, but notlimited to, fine cement, micro fine cement, sulfur, sulfur cement,viscous thermoplastics, or combinations thereof. Fine cement may be ASTMtype 3 Portland cement. Fine cement may be less expensive than microfine cement. In an embodiment, a freeze wellbore is formed in theformation. Selected portions of the freeze wellbore are grouted usingfine cement. Then, micro fine cement is injected into the formationthrough the freeze wellbore. The fine cement may reduce the permeabilitydown to about 10 millidarcy. The micro fine cement may further reducethe permeability to about 0.1 millidarcy. After the grout is introducedinto the formation, a freeze wellbore canister may be inserted into theformation. The process may be repeated for each freeze well that will beused to form the barrier.

In some embodiments, fine cement is introduced into every other freezewellbore. Micro fine cement is introduced into the remaining wellbores.For example, grout may be used in a formation with freeze wellbores setat about 5 m spacing. A first wellbore is drilled and fine cement isintroduced into the formation through the wellbore. A freeze wellcanister is positioned in the first wellbore. A second wellbore isdrilled 10 m away from the first wellbore. Fine cement is introducedinto the formation through the second wellbore. A freeze well canisteris positioned in the second wellbore. A third wellbore is drilledbetween the first wellbore and the second wellbore. In some embodiments,grout from the first and/or second wellbores may be detected in thecuttings of the third wellbore. Micro fine cement is introduced into theformation through the third wellbore. A freeze wellbore canister ispositioned in the third wellbore. The same procedure is used to form theremaining freeze wells that will form the barrier around the treatmentarea.

In some embodiments, in situ vitrification is used to form the barrierof the treatment area. During in situ vitrification, formation ismelted. The melted formation is allowed to slowly solidify to form thebarrier. In situ vitrification is described in U.S. Pat. No. 5,114,277to Murphy et al., which is incorporated by reference as if fully setforth herein. In some embodiments, in situ vitrification is used to formthe barrier before the in situ conversion process produces hydrocarbonsfrom the treatment area. In some embodiments, in situ vitrification isused after in situ conversion to isolate the treated area. In someembodiments, in situ vitrification is used to strengthen or seal one ormore portions of a perimeter barrier during the in situ conversionprocess. In situ vitrification may be used to seal off selected portionsof the treatment area such as aquifer zones that would allow water entryinto the treatment area.

In some embodiments, in situ vitrification is used in combination withfreeze wells to form a double barrier containment system for treatingthe formation. Wellbores for the freeze wells may be formed in theformation. An electrically conductive fluid may be injected into thewellbores and used with the in situ vitrification process to form abarrier in the formation. The relatively close spacing of the freezewells may facilitate formation of an interconnected perimeter barrier bythe in situ vitrification process. After in situ vitrification, freezewells may be installed in the wellbores. The freeze wells may beactivated to form the low temperature zone. Formation fluid entering thelow temperature zone freezes to form the frozen barrier. The frozenbarrier and the solidified wall formed by the in situ vitrificationprocess form the double barrier containment system.

In an embodiment, freeze wells are installed and activated to form thefrozen barrier that isolates the treatment area. Heater wells andproduction wells are formed in the treatment area. The heater wells areactivated and the production wells are used to remove hydrocarbons fromthe treatment area using the in situ conversion process. After thehydrocarbons are produced from the formation, a desired row or rows ofheater wells may be utilized for the in situ vitrification process toform a permanent barrier. The heaters in the desired row or rows ofheater wells may be removed from the formation. The desired row or rowsof wells may be the outermost row or rows of heaters wells. Monitorwells and/or production wells may also be used in the in situvitrification process if needed or desired. The in situ process preparesthe formation for in situ vitrification by removing water, heating theformation to a high temperature, and increasing the permeabilityadjacent to the outermost row or rows of wells. The increasedpermeability allows an electrically conductive fluid injected into theformation to permeate throughout the portions of the formation to besubjected to in situ vitrification.

If selected portions adjacent to the wells are to be subjected to insitu vitrification, packers or isolators may be inserted into the wellsto define the portions to be treated so that the whole depth of theperimeter does not need to be treated. Formation adjacent to the desiredrow or rows of wells may be flushed with carbon dioxide, nitrogen, orother fluid to remove residual contaminants and oxygen from theformation. Graphite or molybdenum electrodes may be inserted into one ormore of the wells to be used for in situ vitrification. An electricallyconductive material, such as a graphite solution or slurry, may beinjected into the wells to flow to adjacent wells to electrically coupleelectrodes in the wells to electrodes in the adjacent wells. Electricalcurrent is applied to the electrodes and the electrically conductivematerial to raise the temperature of the formation adjacent to theelectrodes and electrically conductive material to a temperature in arange from about 1250° C. to about 1600° C. Raising the temperature ofthe formation into this temperature range forms molten formation. Themolten formation may be drawn into the pores and vugs of the formation.The molten formation slowly solidifies to form an impermeable barrierwhen the electrical current is terminated or the molten formation flowssufficiently far away from the electrodes, electrically conductivematerial, and the molten formation cools. Vapors produced during the insitu vitrification process may be removed from the formation throughproduction wells in the treatment area. After formation of theimpermeable barrier by the in situ vitrification process, maintenance ofthe freeze wall may be ended.

In certain embodiments, a barrier may be formed in the formation afteran in situ conversion process or a solution mining process byintroducing a fluid into the formation. The in situ conversion processmay heat the treatment area and greatly increase the permeability of thetreatment area. The solution mining process may remove material from thetreatment area and greatly increase the permeability of the treatmentarea. In certain embodiments, the treatment area has an increasedpermeability of at least 0.1 darcy. In some embodiments, the treatmentarea has an increased permeability of at least 1 darcy, of at least 10darcy, or of at least 100 darcy. The increased permeability allows thefluid to spread in the formation into fractures, microfractures, and/orpore spaces in the formation. The fluid may include bitumen, heavy oil,sulfur, polymer, saturated saline solution, and/or a reactant orreactants that react to form a precipitate, solid or a high viscosityfluid in the formation. In some embodiments, bitumen, heavy oil, and/orsulfur used to form the barrier are obtained from treatment facilitiesof the in situ conversion process.

The fluid may be introduced into the formation as a liquid, vapor, ormixed phase fluid. The fluid may be introduced into a portion of theformation that is at an elevated temperature. In some embodiments, thefluid is introduced into the formation through wells located near aperimeter of the treatment area. The fluid may be directed away from thetreatment area. The elevated temperature of the formation maintains orallows the fluid to have a low viscosity so that the fluid moves awayfrom the wells. A portion of the fluid may spread outwards in theformation towards a cooler portion of the formation. In the coolerportion of the formation, the viscosity of the fluid increases, aportion of the fluid precipitates, and/or the fluid solidifies so thatthe fluid forms the barrier to flow of formation fluid into or out ofthe treatment area.

In some embodiments, a low temperature barrier formed by freeze wellssurrounds all or a portion of the treatment area. As the fluidintroduced into the formation approaches the low temperature barrier,the temperature of the formation becomes colder. The colder temperatureincreases the viscosity of the fluid, enhances precipitation, and/orsolidifies the fluid to form the barrier to the flow of formation fluidinto or out of the formation. The fluid may remain in the formation as ahighly viscous fluid or a solid after the low temperature barrier hasdissipated.

In certain embodiments, saturated saline solution is introduced into theformation. Particles in the saturated saline solution may precipitateout of solution when the solution reaches a colder temperature. Thesolidified particles may form the barrier to the flow of formation fluidinto or out of the formation. The solidified particles may besubstantially insoluble in formation fluid.

In certain embodiments, brine with a selected crystallogy is introducedinto the formation as a reactant. A second reactant, such a carbondioxide may be introduced into the formation to react with the brine andform a mineral complex in the formation that is substantially insolubleto formation fluid. In an embodiment, the brine solution includes asodium and aluminum solution. The second reactant introduced in theformation is carbon dioxide. The carbon dioxide reacts with the brinesolution to produce dawsonite. The minerals may solidify and form thebarrier to the flow of formation fluid into or out of the formation.

In some embodiments, the barrier may be formed using sulfur. Sulfur maybe introduced into the formation through wells located near theperimeter of the treatment area. At least a portion of the sulfurspreads outwards from the treatment area towards a cooler portion of theformation. The introduced sulfur spreads outward and solidifies in theformation to form a sulfur barrier. The solidified sulfur in theformation forms a barrier to formation fluid flow into or out of thetreatment area.

A temperature monitoring system may be installed in wellbores of freezewells and/or in monitor wells adjacent to the freeze wells to monitorthe temperature profile of the freeze wells and/or the low temperaturezone established by the freeze wells. The monitoring system may be usedto monitor progress of low temperature zone formation. The monitoringsystem may be used to determine the location of high temperature areas,potential breakthrough locations, or breakthrough locations after thelow temperature zone has formed. Periodic monitoring of the temperatureprofile of the freeze wells and/or low temperature zone established bythe freeze wells may allow additional cooling to be provided topotential trouble areas before breakthrough occurs. Additional coolingmay be provided at or adjacent to breakthroughs and high temperatureareas to ensure the integrity of the low temperature zone around thetreatment area. Additional cooling may be provided by increasingrefrigerant flow through selected freeze wells, installing an additionalfreeze well or freeze wells, and/or by providing a cryogenic fluid, suchas liquid nitrogen, to the high temperature areas. Providing additionalcooling to potential problem areas before breakthrough occurs may bemore time efficient and cost efficient than sealing a breach, reheatinga portion of the treatment area that has been cooled by influx of fluid,and/or remediating an area outside of the breached frozen barrier.

In some embodiments, a traveling thermocouple may be used to monitor thetemperature profile of selected freeze wells or monitor wells. In someembodiments, the temperature monitoring system includes thermocouplesplaced at discrete locations in the wellbores of the freeze wells, inthe freeze wells, and/or in the monitoring wells. In some embodiments,the temperature monitoring system comprises a fiber optic temperaturemonitoring system.

Fiber optic temperature monitoring systems are available from Sensomet(London, United Kingdom), Sensa (Houston, Tex., U.S.A.), Luna Energy(Blacksburg, Va., U.S.A.), Lios Technology GMBH (Cologne, Germany),Oxford Electronics Ltd. (Hampshire, United Kingdom), and Sabeus SensorSystems (Calabasas, Calif., U.S.A.). The fiber optic temperaturemonitoring system includes a data system and one or more fiber opticcables. The data system includes one or more lasers for sending light tothe fiber optic cable; and one or more computers, software andperipherals for receiving, analyzing, and outputting data. The datasystem may be coupled to one or more fiber optic cables.

A single fiber optic cable may be several kilometers long. The fiberoptic cable may be installed in many freeze wells and/or monitor wells.In some embodiments, two fiber optic cables may be installed in eachfreeze well and/or monitor well. The two fiber optic cables may becoupled. Using two fiber optic cables per well allows for compensationdue to optical losses that occur in the wells and allows for betteraccuracy of measured temperature profiles.

A fiber of a fiber optic cable may be placed in a polymer tube. Thepolymer tube may be filled with a heat transfer fluid. The heat transferfluid may be a gel or liquid that does not freeze at or above thetemperature of formation refrigerant used to cool the formation. In someembodiments the heat transfer fluid in the polymer tube is the same asthe formation refrigerant, for example, a fluid available from Dynalene®Heat Transfer Fluids or aqua ammonia. In some embodiments, the fiber isblown into the tube using the heat transfer fluid. Using the heattransfer fluid to insert the fiber into the polymer tube removesmoisture from the polymer tube.

In some embodiments, a protective sleeve is strapped to the canister ofthe freeze well as the canister is introduced into the formation. Theprotective sleeve may be in a u-shape. A turn-around sub near the end ofthe canister may accommodate the u-turn in the protective sleeve. Afiber may be inserted in the protective sleeve. FIG. 21 depicts aportion of canister 410 with protective sleeve 482 coupled to thecanister by straps 484. Protective sleeve 482 may be stainless steeltubing or other tubing.

The polymer tube and fiber may be placed in the protective sleeve, suchas ¼ inch 304 stainless steel tubing, to form the fiber optic cable. Theprotective sleeve may be prestressed to accommodate thermal contractionat low temperatures. The protective sleeve may be filled with the heattransfer fluid. In some embodiments, the polymer tube is blown into theprotective sleeve with the heat transfer fluid. Using the heat transferfluid to insert the polymer tube and fiber into the protective sleeveremoves moisture from the protective sleeve. In some embodiments, twofibers are positioned in the same stainless steel tube. In someembodiments, the fiber is placed directly in the protective sleevewithout being placed in a polymer tube.

In some embodiments, the fiber optic cable is strapped to the canisterof the freeze well as the canister is inserted into the formation. Thefiber optic cable may be coiled around the canister adjacent to theportions of the formation that are to be reduced to low temperature toform the low temperature zone. Coiling the fiber optic cable around thecanister allows a large length of the fiber optic cable to be adjacentto areas that are to be reduced to low temperature. The large lengthallows for better resolution of the temperature profile for the areas tobe reduced to low temperatures. In some embodiments, the fiber opticcable is placed in the canister of the freeze well.

FIG. 22 depicts a schematic representation of a fiber optic temperaturemonitoring system. Data system 486 includes laser 488 and analyzer 490.Laser 488 injects short, intense light pulses into fiber optic cable492. Fiber optic cable 492 is positioned in a plurality of freeze wells408 and monitor wells 494. Fiber optic cable 492 may be strapped to thecanisters of the freeze wells as the canisters are installed in theformation. In some embodiments, the fiber optic cable is strapped tosupports and inserted into the monitor wells. In some embodiments, theprotective sleeve of the fiber optic cable may be suspended in themonitor wells without an additional support. Backscattering andreflection of light in fiber optic cable 492 may be measured as afunction of time by analyzer 490 of the data system 486. Analysis of thebackscattering and reflection of light data yields a temperature profilealong the length of fiber optic cable 492.

In some embodiments, the data system is a double ended system. The datasystem may include one or more lasers that send light pulses into eachend of the fiber optic cable. In some embodiments, the laser is onelaser. The laser sends pulses to each end of the fiber optic cable in analternating manner. The return signals received by the data systemallows for compensation of signal attenuation in the optical fiber.

In some embodiments, computer control system 496 is in communicationwith the fiber optic temperature monitoring system and the formationrefrigeration circulation system. The formation refrigerationcirculation system may include refrigeration system 498. Refrigerationsystem 498 sends chilled formation refrigerant to wellheads 418 offreeze wells 408 through piping 500. In some embodiments, the formationrefrigerant passes down the inlet conduit of the freeze well and upthrough the annular space between the inlet conduit and the freeze wellcanister. The formation refrigerant then passes through piping 500 tothe next freeze well.

Computer control system 496 may allow for automatic monitoring of thelow temperature zone established by freeze wells 408. Computer controlsystem 496 may periodically shut down the flow of formation refrigerantto a set of freeze wells for a given time. For example, computer controlsystem 496 may shut down the flow of formation refrigerant to a specificset of freeze wells every 60 days for a period of two days and activatedata system 486 to monitor the temperature profile near the shut downfreeze wells. The temperature profile of the freeze wells with noformation refrigerant flow will begin to rise.

Computer control system 496 may monitor the rate of increase oftemperature. If there is a problem area, the temperature profile nearthe problem area will show a greater rate of change than the temperatureprofile of adjacent areas. If a larger than expected temperatureincrease occurs at approximately the same depth location at or near twoadjacent wells, the computer control system may signal that there is aproblem to an operator of the system. The location of the problem areamay be estimated/modeled/assessed by comparing the temperature increasesbetween adjacent wells. For example, if the temperature increase in afirst well is twice as large as the temperature increase in a secondwell, then the location of the problem area is likely closer to thefirst well. Extra cooling and/or extra monitoring can be provided toproblem areas. Extra cooling may be provided by increasing the flow offormation refrigerant to the problem area and/or by installing one ormore additional freeze wells. If no problems are detected during thegiven time, the computer system restarts the flow of formation fluid tothe specific set of freeze wells and begins a test of another set offreeze wells. Using computer control system 496 to monitor the lowtemperature zone established by freeze wells allows for problems to bedetected and fixed before a breach of the barrier formed by the freezewells occurs.

In some embodiments, the fiber optic temperature monitoring systemutilizes Brillouin or Raman scattering systems. Such systems providespatial resolution of 1 m and temperature resolution of 0.1° C. Withsufficient averaging and temperature calibration, the systems may beaccurate to 0.5° C.

In some embodiments, the fiber optic temperature monitoring system maybe a Bragg system that uses a fiber optic cable etched with closelyspaced Bragg gratings. The Bragg gratings may be formed in 1 footincrements along selected lengths of the fiber. Fibers with Bragggratings are available from Luna Energy. The Bragg system only requiresa single fiber optic cable to be placed in each well that is to bemonitored. The Bragg system is able to measure the fiber temperature ina few seconds.

The fiber optic temperature monitoring system may be used to detect thelocation of a breach or a potential breach in a frozen barrier. Thesearch for potential breaches may be performed at scheduled intervals,for example, every two or three months. To determine the location of thebreach or potential breach, flow of formation refrigerant to the freezewells of interest is stopped. In some embodiments, the flow of formationrefrigerant to all of the freeze wells is stopped. The rise in thetemperature profiles, as well as the rate of change of the temperatureprofiles, provided by the fiber optic temperature monitoring system foreach freeze well can be used to determine the location of any breachesor hot spots in the low temperature zone maintained by the freeze wells.The temperature profile monitored by the fiber optic temperaturemonitoring system for the two freeze wells closest to the hot spot orfluid flow will show the quickest and greatest rise in temperature. Atemperature change of a few degrees Centigrade in the temperatureprofiles of the freeze wells closest to a troubled area may besufficient to isolate the location of the trouble area. The shut downtime of flow of circulation fluid in the freeze wells of interest neededto detect breaches, potential breaches, and hot spots may be on theorder of a few hours or days, depending on the well spacing and theamount of fluid flow affecting the low temperature zone.

Fiber optic temperature monitoring systems may also be used to monitortemperatures in heated portions of the formation during in situconversion processes. The fiber of a fiber optic cable used in theheated portion of the formation may be clad with a reflective materialto facilitate retention of a signal or signals transmitted down thefiber. In some embodiments, the fiber is clad with gold, copper, nickel,aluminum and/or alloys thereof. The cladding may be formed of a materialthat is able to withstand chemical and temperature conditions in theheated portion of the formation. For example, gold cladding may allow anoptical sensor to be used up to temperatures of 700° C. In someembodiments, the fiber is clad with aluminum. The fiber may be dipped inor run through a bath of liquid aluminum. The clad fiber may then beallowed to cool to secure the aluminum to the fiber. The gold oraluminum cladding may reduce hydrogen darkening of the optical fiber.

In some embodiments, heaters that heat hydrocarbons in the formation maybe close to the low temperature zone established by freeze wells. Insome embodiments, heaters may be may be 20 m, 10 m, 5 m or less from anedge of the low temperature zone established by freeze wells. In someembodiments, heat interceptor wells may be positioned between the lowtemperature zone and the heaters to reduce the heat load applied to thelow temperature zone from the heated part of the formation. FIG. 23depicts a schematic view of the well layout plan for heater wells 502,production wells 206, heat interceptor wells 504, and freeze wells 408for a portion of an in situ conversion system embodiment. Heatinterceptor wells 504 are positioned between heater wells 502 and freezewells 408.

Some heat interceptor wells may be formed in the formation specificallyfor the purpose of reducing the heat load applied to the low temperaturezone established by freeze wells. Some heat interceptor wells may beheater wellbores, monitor wellbores, production wellbores, dewateringwellbores, or other type of wellbores that are converted for use as heatinterceptor wells.

In some embodiments, heat interceptor wells may function as heat pipesto reduce the heat load applied to the low temperature zone. A liquidheat transfer fluid may be placed in the heat interceptor wellbores. Theliquid may include, but is not limited to, water, alcohol, and/oralkanes. Heat supplied to the formation from the heaters may advance tothe heat interceptor wellbores and vaporize the liquid heat transferfluid in the heat interceptor wellbores. The resulting vapor may rise inthe wellbores. Above the heated portion of the formation adjacent to theoverburden, the vapor may condense and flow by gravity back to the areaadjacent to the heated part of the formation. The heat absorbed bychanging the phase of the liquid heat transfer fluid reduces the heatload applied to the low temperature zone. Using heat interceptor wellsthat function as heat pipes may be advantageous for formations withthick overburdens that are able to absorb the heat applied as the heattransfer fluid changes phase from vapor to liquid. The wellbore mayinclude wicking material, packing to increase surface area adjacent to aportion of the overburden, or other material to promote heat transfer toor from the formation and the heat transfer fluid.

In some embodiments, a heat transfer fluid is circulated through theheat interceptor wellbores in a closed loop system. A heat exchangerreduces the temperature of the heat transfer fluid after the heattransfer fluid leaves the heat interceptor wellbores. Cooled heattransfer fluid is pumped through the heat interceptor wellbores. In someembodiments, the heat transfer fluid does not undergo a phase changeduring use. In some embodiments, the heat transfer fluid may changephases during use. The heat transfer fluid may be, but is not limitedto, water, alcohol, and/or glycol.

A potential source of heat loss from the heated formation is due toreflux in wells. Refluxing occurs when vapors condense in a well andflow into a portion of the well adjacent to the heated portion of theformation. Vapors may condense in the well adjacent to the overburden ofthe formation to form condensed fluid. Condensed fluid flowing into thewell adjacent to the heated formation absorbs heat from the formation.Heat absorbed by condensed fluids cools the formation and necessitatesadditional energy input into the formation to maintain the formation ata desired temperature. Some fluids that condense in the overburden andflow into the portion of the well adjacent to the heated formation mayreact to produce undesired compounds and/or coke. Inhibiting fluids fromrefluxing may significantly improve the thermal efficiency of the insitu conversion system and/or the quality of the product produced fromthe in situ conversion system.

For some well embodiments, the portion of the well adjacent to theoverburden section of the formation is cemented to the formation. Insome well embodiments, the well includes packing material placed nearthe transition from the heated section of the formation to theoverburden. The packing material inhibits formation fluid from passingfrom the heated section of the formation into the section of thewellbore adjacent to the overburden. Cables, conduits, devices, and/orinstruments may pass through the packing material, but the packingmaterial inhibits formation fluid from passing up the wellbore adjacentto the overburden section of the formation.

In some embodiments, a gas may be introduced into the formation throughwellbores to inhibit reflux in the wellbores. In some embodiments, gasmay be introduced into wellbores that include baffle systems to inhibitreflux of fluid in the wellbores. The gas may be carbon dioxide,methane, nitrogen or other desired gas.

In some well embodiments, a ball type reflux baffle system may be usedin heater wells to inhibit reflux. FIG. 24 depicts an embodiment of balltype reflux baffle system positioned in a cased portion of a heaterwell. Ball type reflux baffle may include insert 506, and balls 508. Aportion of heater element 510 passes through insert 506. The portion ofheater element 510 that passes through insert 506 is a portion of theheater element that does not heat to a high temperature. Insert 506 maybe made of metal, plastic and/or steel able to withstand temperatures ofover 160° C. In an embodiment, insert 506 is made of phenolic resin.

Insert 506 may be guided down the casing of the wellbore using a coiltubing guide string. Insert 506 may be set in position using slips thatfit in one or more indentions in the insert, using protrusions of theinsert that fit in one or more recesses in the casing, or the insert mayrest on a shoulder of the casing. After removal of the coil tubing guidestring, balls 508 may be dropped down the casing onto insert 506. Ballsmay be made of any desired material able to withstand temperatures ofover 160° C. In some embodiments, balls 510 are made of silicon nitride.Balls of varying diameters may be used. Balls inhibit fluid convection.

During the in situ conversion process, heater element 510 may need to bepulled from the well. When heater element 510 is removed from the well,balls 508 may pass through insert 506 to the bottom of the well. Anotherheater element may be installed in the well, and additional balls may bedropped down the well to land on insert 506.

In some embodiments, one or more circular baffles may be coupled to aportion of a heating element to inhibit convection of fluid. The bafflesmay substantially fill the annular space between the heating element andthe casing. The baffles may be made of an electrically insulativematerial such as a ceramic, or plastic. In some embodiments, the bafflesmay be made of fiberglass or silicon nitride. The baffles may positionthe heating element in the center of the casing.

The ball type baffle system and/or the circular baffle system may workbetter if a gas purge is introduced into the wellbore. The gas purge maymaintain sufficient pressure in the wellbore to inhibit fluid flow fromthe heated portion of the formation into the wellbore. The gas purge mayenhance heat exchange at the baffle system to help maintain a topportion of the baffle system colder than the lower portion of the bafflesystem.

The flow of production fluid up the well to the surface is desired forsome types of wells, especially for production wells. Flow of productionfluid up the well is also desirable for some heater wells that are usedto control pressure in the formation. The overburden, or a conduit inthe well used to transport formation fluid from the heated portion ofthe formation to the surface, may be heated to inhibit condensation onor in the conduit. Providing heat in the overburden, however, may becostly and/or may lead to increased cracking or coking of formationfluid as the formation fluid is being produced from the formation.

To avoid the need to heat the overburden or to heat the conduit passingthrough the overburden, one or more diverters may be placed in thewellbore to inhibit fluid from refluxing into the wellbore adjacent tothe heated portion of the formation. In some embodiments, the diverterretains fluid above the heated portion of the formation. Fluids retainedin the diverter may be removed from the diverter using a pump, gaslifting, and/or other fluid removal technique. In some embodiments, thediverter directs fluid to a pump, gas lift assembly, or other fluidremoval device located below the heated portion of the formation.

FIG. 25 depicts an embodiment of a diverter in a production well.Production well 206 includes conduit 512. In some embodiments, diverter514 is coupled to or located proximate production conduit 512 inoverburden 382. In some embodiments, the diverter is placed in theheated portion of the formation. Diverter 514 may be located at or nearan interface of overburden 382 and hydrocarbon layer 380. Hydrocarbonlayer 380 is heated by heat sources located in the formation. Diverter514 may include packing 520, riser 522, and seal 516 in productionconduit 512. Formation fluid in the vapor phase from the heatedformation moves from hydrocarbon layer 380 into riser 522. In someembodiments, riser 522 is perforated below packing 520 to facilitatemovement of fluid into the riser. Packing 520 inhibits passage of thevapor phase formation fluid into an upper portion of production well206. Formation fluid in the vapor phase moves through riser 522 intoproduction conduit 512. A non-condensable portion of the formation fluidrises through production conduit 512 to the surface. The vapor phaseformation fluid in production conduit 512 may cool as it rises towardsthe surface in the production conduit. If a portion of the vapor phaseformation fluid condenses to liquid in production conduit 512, theliquid flows by gravity towards seal 516. Seal 516 inhibits liquid fromentering the heated portion of the formation. Liquid collected aboveseal 516 is removed by pump 518 through conduit 532. Pump 518 may be,but is not limited to being, a sucker rod pump, an electrical pump, or aprogressive cavity pump (Moyno style). In some embodiments, liquid aboveseal 516 is gas lifted through conduit 532. Producing condensed fluidmay reduce costs associated with removing heat from fluids at thewellhead of the production well.

In some embodiments, production well 206 includes heater 534. Heater 534provides heat to vaporize liquids in a portion of production well 206proximate hydrocarbon layer 380. Heater 534 may be located in productionconduit 512 or may be coupled to the outside of the production conduit.In embodiments where the heater is located outside of the productionconduit, a portion of the heater passes through the packing material.

In some embodiments, a diluent may be introduced into production conduit512 and/or conduit 532. The diluent is used to inhibit clogging inproduction conduit 512, pump 518, and/or conduit 532. The diluent maybe, but is not limited to being, water, an alcohol, a solvent, and/or asurfactant.

In some embodiments, riser 522 extends to the surface of production well206. Perforations and a baffle in riser 522 located above seal 516direct condensed liquid from the riser into production conduit 512.

In certain embodiments; two or more diverters may be located in theproduction well. Two or more diverters provide a simple way ofseparating initial fractions of condensed fluid produced from the insitu conversion system. A pump may be placed in each of the diverters toremove condensed fluid from the diverters.

In some embodiments, fluids (gases and liquids) may be directed towardsthe bottom of the production well using the diverter. The fluids may beproduced from the bottom of the production well. FIG. 26 depicts anembodiment of the diverter that directs fluid towards the bottom of theproduction well. Diverter 514 may include packing material 520 andbaffle 538 positioned in production conduit 512. Baffle may be a pipepositioned around conduit 532. Production conduit 512 may have openings528 that allow fluids to enter the production conduit from hydrocarbonlayer 380. In some embodiments, all or a portion of the openings areadjacent to a non-hydrocarbon layer of the formation through whichheated formation fluid flows. Openings 528 include, but are not limitedto, screens, perforations, slits, and/or slots. Hydrocarbon layer 380may be heated using heaters located in other portions of the formationand/or a heater located in production conduit 512.

Baffle 538 and packing material 520 direct formation fluid enteringproduction conduit 512 to unheated zone 530. Unheated zone 530 is in theunderburden of the formation. A portion of the formation fluid maycondense on the outer surface of baffle 538 or on walls of productionconduit 512 adjacent to unheated zone 530. Liquid fluid from theformation and/or condensed fluid may flow by gravity to a sump or bottomportion of production conduit 512. Liquid and condensate in the bottomportion of production conduit 512 may be pumped to the surface throughconduit 532 using pump 518. Pump 518 may be placed 1 m, 5 m, 10 m, 20 mor more into the underburden. In some embodiments, the pump may beplaced in a non-cased (open) portion of the wellbore. Non-condensedfluid initially travels through the annular space between baffle 538 andconduit 532, and then through the annular space between productionconduit 512 and conduit 532 to the surface, as indicated by arrows inFIG. 26. If a portion of the non-condensed fluid condenses adjacent tooverburden 382 while traveling to the surface, the condensed fluid willflow by gravity toward the bottom portion of production conduit 512 tothe intake for pump 518. Heat absorbed by the condensed fluid as thefluid passes through the heated portion of the formation is from contactwith baffle 538, not from direct contact with the formation. Baffle 538is heated by formation fluid and radiative heat transfer from theformation. Significantly less heat from the formation is transferred tothe condensed fluid as the fluid flows through baffle 538 adjacent tothe heated portion than if the condensed fluid was able to contact theformation. The condensed fluid flowing down the baffle may absorb enoughheat from the vapor in the wellbore to condense a portion of the vaporon the outer surface of baffle 538. The condensed portion of the vapormay flow down the baffle to the bottom portion of the wellbore.

In some embodiments, diluent may be introduced into production conduit512 and/or conduit 532. The diluent is used to inhibit clogging inproduction conduit 512, pump 518, and conduit 532. The diluent mayinclude, but is not limited to, water, an alcohol, a solvent, asurfactant, or combinations thereof. Different diluents may beintroduced at different times. For example, a solvent may be introducedwhen production first begins to put into solution high molecular weighthydrocarbons that are initially produced from the formation. At a latertime, water may be substituted for the solvent.

In some embodiments, a separate conduit may introduce the diluent to thewellbore near the underburden, as depicted in FIG. 27. Productionconduit 512 directs vapor produced from the formation to the surfacethrough overburden 382. If a portion of the vapor condenses inproduction conduit 512, the condensate can flow down baffle 538 to theintake for pump 518. Diverter 514, comprising packing material 520 andbaffle 538, directs formation fluid flow from heated hydrocarbon layer380 to unheated zone 530. Liquid formation fluid is transported by pump518 through conduit 532 to the surface. Vapor formation fluid istransported through baffle 538 to production conduit 512. Conduit 540may be strapped to baffle 538. Conduit 540 may introduce the diluent towellbore 542 adjacent to unheated zone 530. The diluent may promotecondensation of formation fluid and/or inhibit clogging of pump 518.Diluent in conduit 540 may be at a high pressure. If the diluent changesphase from liquid to vapor while passing through the heated portion ofthe formation, the change in pressure as the diluent leaves conduit 540allows the diluent to condense.

In some embodiments, the intake of the pump system is located in casingin the sump. In some embodiments, the intake of the pump system islocated in an open wellbore. The sump is below the heated portion of theformation. The intake of the pump may be located 1 m, 5 m, 10 m, 20 m ormore below the deepest heater used to heat the heated portion of theformation. The sump may be at a cooler temperature than the heatedportion of the formation. The sump may be more than 10° C., more than50° C., more than 75° C., or more than 100° C. below the temperature ofthe heated portion of the formation. A portion of the fluid entering thesump may be liquid. A portion of the fluid entering the sump maycondense within the sump.

Production well lift systems may be used to efficiently transportformation fluid from the bottom of the production wells to the surface.Production well lift systems may provide and maintain the maximumrequired well drawdown (minimum reservoir producing pressure) andproducing rates. The production well lift systems may operateefficiently over a wide range of high temperature/multiphase fluids(gas/vapor/steam/water/hydrocarbon liquids) and production ratesexpected during the life of a typical project.

FIG. 28 illustrates an embodiment of a dual concentric rod pump liftsystem for use in production wells. The formation fluid enters thewellbore from heated portion 536. Formation fluid may be transported tothe surface through inner conduit 544 and outer conduit 546. Innerconduit 544 and outer conduit 546 may be concentric. Concentric conduitsmay be advantageous over dual (side by side) conduits in conventionaloilfield production wells. Inner conduit 544 may be used for productionof liquids. Outer conduit 546 may allow vapor and/or gaseous phaseformation fluids to flow to the surface along with some entrainedliquids.

The diameter of outer conduit 546 may be chosen to allow a desired rangeof flow rates and/or to minimize the pressure drop and flowing reservoirpressure. Reflux seal 556 at the base of outer conduit 546 may inhibithot produced gases and/or vapors from contacting the relatively coldwall of well casing 548 above heated portion 536. This minimizespotentially damaging and wasteful energy losses from heated portion 536via condensation and recycling of fluids. Reflux seal 556 may be adynamic seal, allowing outer conduit 546 to thermally expand andcontract while being fixed at surface 550. Reflux seal 556 may be aone-way seal designed to allow fluids to be pumped down annulus 552 fortreatment or for well kill operations. For example, down-facingelastomeric-type cups may be used in reflux seal 556 to inhibit fluidsfrom flowing upward through annulus 552. In some embodiments, refluxseal 556 is a “fixed” design, with a dynamic wellhead seal that allowsouter conduit 546 to move at surface 550, thereby reducing thermalstresses and cycling.

Conditions in any particular well or project could allow both ends ofouter conduit 546 to be fixed. Outer conduit 546 may require no orinfrequent retrieval for maintenance over the expected useful life ofthe production well. In some embodiments, utility bundle 554 is coupledto the outside of outer conduit 546. Utility bundle 554 may include, butis not limited to, conduits for monitoring, control, and/or treatmentequipment such as temperature/pressure monitoring devices, chemicaltreatment lines, diluent injection lines, and cold fluid injection linesfor cooling of the liquid pumping system. Coupling utility bundle 554 toouter conduit 546 may allow the utility bundle (and thus the potentiallycomplex and sensitive equipment included in this bundle) to remain inplace during retrieval and/or maintenance of inner conduit 544. Incertain embodiments, outer conduit 546 is removed one or more times overthe expected useful life of the production well.

Annulus 552 between well casing 548 and outer conduit 546 may provide aspace to run utility bindle 554 and instrumentation, as well as thermalinsulation to optimize and/or control temperature and/or behavior of theproduced fluid. In some embodiments, annulus 552 is filled with one ormore fluids or gases (pressurized or not) to allow regulation of theoverall thermal conductivity and resulting heat transfer between theoverburden and the formation fluid being produced. Using annulus 552 asa thermal barrier may allow: 1) optimization of temperature and/or phasebehavior of the fluid stream for subsequent processing of the fluidstream at the surface, and/or 2) optimization of multiphase behavior toenable maximum natural flow of fluids and liquid stream pumping. Theconcentric configuration of outer conduit 546 and inner conduit 544 isadvantageous in that the heat transfer/thermal effects on the fluidstreams are more uniform than a conventional dual (parallel tubing)configuration.

Inner conduit 544 may be used for production of liquids. Liquidsproduced from inner conduit 544 may include fluids in liquid form thatare not entrained with gas/vapor produced from outer conduit 546, aswell as liquids that condense in the outer conduit. In some embodiments,the base of inner conduit 544 is positioned below the base of heatedportion 536 (in sump 558) to assist in natural gravity separation of theliquid phase. Sump 558 may be a separation sump. Sump 558 may alsoprovide thermal benefits (for example, cooler pump operation and reducedliquid flashing in the pump) depending upon the length/depth of the sumpand overall fluid rates and/or temperatures.

Inner conduit 544 may include a pump system. In some embodiments, pumpsystem 560 is an oilfield-type reciprocating rod pump. Such pumps areavailable in a wide variety of designs and configurations. Reciprocatingrod pumps have the advantages of being widely available and costeffective. In addition, surveillance/evaluation analysis methods arewell-developed and understood for this system. In certain embodiments,the prime mover is advantageously located on the surface foraccessibility and maintenance. Location of the prime mover on thesurface also protects the prime mover from the extreme temperature/fluidenvironment of the wellbore. FIG. 28 depicts a conventionaloilfield-type beam-pumping unit on surface 550 for reciprocation of rodstring 562. Other types of pumping units may be used including, but notlimited to, hydraulic units, long-stroke units, air-balance units,surface-driven rotary units, and MII units. A variety of surfaceunit/pump combinations may be employed depending on well conditions anddesired pumping rates. In certain embodiments, inner conduit 544 isanchored to limit movement and wear of the inner conduit.

Concentric placement of outer conduit 546 and inner conduit 544 mayfacilitate maintenance of the inner conduit and the associated pumpsystem, including intervention and/or replacement of downholecomponents. The concentric design allows formaintenance/removal/replacement of inner conduit 544 without disturbingouter conduit 546 and related components, thus lowering overallexpenses, reducing well downtime, and/or improving overall projectperformance compared to a conventional parallel double conduitconfiguration. The concentric configuration may also be modified toaccount for unexpected changes in well conditions over time. The pumpsystem can be quickly removed and both conduits may be utilized forflowing production in the event of lower liquid rates or much highervapor/gas rates than anticipated. Conversely, a larger or differentsystem can easily be installed in the inner conduit without affectingthe balance of the system components.

Various methods may be used to control the pump system to enhanceefficiency and well production. These methods may include, for example,the use of on/off timers, pump-off detection systems to measure surfaceloads and model the downhole conditions, direct fluid level sensingdevices, and sensors suitable for high-temperature applications(capillary tubing, etc.) to allow direct downhole pressure monitoring.In some embodiments, the pumping capacity is matched with availablefluid to be pumped from the well.

Various design options and/or configurations for the conduits and/or rodstring (including materials, physical dimensions, and connections) maybe chosen to enhance overall reliability, cost, ease of initialinstallation, and subsequent intervention and/or maintenance for a givenproduction well. For example, connections may be threaded, welded, ordesigned for a specific application. In some embodiments, sections ofone or more of the conduits are connected as the conduit is lowered intothe well. In certain embodiments, sections of one or more of theconduits are connected prior to insertion in the well, and the conduitis spooled (for example, at a different location) and later unspooledinto the well. The specific conditions within each production welldetermine equipment parameters such as equipment sizing, conduitdiameters, and sump dimensions for optimal operation and performance.

FIG. 29 illustrates an embodiment of the dual concentric rod pump systemincluding 2-phase separator 564 at the bottom of inner conduit 544 toaid in additional separation and exclusion of gas/vapor phase fluidsfrom rod pump 560. Use of 2-phase separator 564 may be advantageous athigher vapor and gas/liquid ratios. Use of 2-phase separator 564 mayhelp prevent gas locking and low pump efficiencies in inner conduit 544.

FIG. 30 depicts an embodiment of the dual concentric rod pump systemthat includes gas/vapor shroud 566 extending down into sump 558.Gas/vapor shroud 566 may force the majority of the produced fluid streamdown through the area surrounding sump 558, increasing the naturalliquid separation. Gas/vapor shroud 566 may include sized gas/vapor vent568 at the top of the heated zone to inhibit gas/vapor pressure frombuilding up and being trapped behind the shroud. Thus, gas/vapor shroud566 may increase overall well drawdown efficiency, and becomes moreimportant as the thickness of heated portion 536 increases. The size ofgas/vapor vent 568 may vary and can be determined based on the expectedfluid volumes and desired operating pressures for any particularproduction well.

FIG. 31 depicts an embodiment of a chamber lift system for use inproduction wells. Conduit 570 provides a path for fluids of all phasesto be transported from heated portion 536 to surface 550. Packer/refluxseal assembly 572 is located above heated portion 536 to inhibitproduced fluids from entering annulus 552 between conduit 570 and wellcasing 548 above the heated portion. Packer/reflux seal assembly 572 mayreduce the refluxing of the fluid, thereby advantageously reducingenergy losses. In this configuration, packer/reflux seal assembly 572may substantially isolate the pressurized lift gas in annulus 552 abovethe packer/reflux seal assembly from heated portion 536. Thus, heatedportion 536 may be exposed to the desired minimum drawdown pressure,maximizing fluid inflow to the well. As an additional aid in maintaininga minimum drawdown pressure, sump 558 may be located in the wellborebelow heated portion 536. Produced fluids/liquids may therefore collectin the wellbore below heated portion 536 and not cause excessivebackpressure on the heated portion. This becomes more advantageous asthe thickness of heated portion 536 increases.

Fluids of all phases may enter the well from heated portion 536. Thesefluids are directed downward to sump 558. The fluids enter lift chamber574 through check valve 576 at the base of the lift chamber. Aftersufficient fluid has entered lift chamber 574, lift gas injection valve578 opens and allows pressurized lift gas to enter the top of the liftchamber. Crossover port 580 allows the lift gas to pass throughpacker/reflux seal assembly 572 into the top of lift chamber 574. Theresulting pressure increase in lift chamber 574 closes check valve 576at the base and forces the fluids into the bottom of diptube 582, upinto conduit 570, and out of the lift chamber. Lift gas injection valve578 remains open until sufficient lift gas has been injected to evacuatethe fluid in lift chamber 574 to a collection device. Lift gas injectionvalve 578 then closes and allows lift chamber 574 to fill with fluidagain. This “lift cycle” repeats (intermittent operation) as often asnecessary to maintain the desired drawdown pressure within heatedportion 536. Sizing of equipment, such as conduits, valves, and chamberlengths and/or diameters, is dependent upon the expected fluid ratesproduced from heated portion 536 and the desired minimum drawdownpressure to be maintained in the production well.

In some embodiments, the entire chamber lift system may be retrievablefrom the well for repair, maintenance, and periodic design revisions dueto changing well conditions. However, the need for retrieving conduit570, packer/reflux seal assembly 572, and lift chamber 574 may berelatively infrequent. In some embodiments, lift gas injection valve 578is configured to be retrieved from the well along with conduit 570. Incertain embodiments, lift gas injection valve 578 is configured to beseparately retrievable via wireline or similar means without removingconduit 570 or other system components from the well. Check valve 576and/or diptube 582 may be individually installed and/or retrieved in asimilar manner. The option to retrieve diptube 582 separately may allowre-sizing of gas/vapor vent 568. The option to retrieve these individualcomponents (items that would likely require the most frequent wellintervention, repair, and maintenance) greatly improves theattractiveness of the system from a well intervention and maintenancecost perspective.

Gas/vapor vent 568 may be located at the top of diptube 582 to allow gasand/or vapor entering the lift chamber from heated portion 536 tocontinuously vent into conduit 570 and inhibit an excess buildup ofchamber pressure. Inhibiting an excess buildup of chamber pressure mayincrease overall system efficiency. Gas/vapor vent 568 may be sized toavoid excessive bypassing of injected lift gas into conduit 570 duringthe lift cycle, thereby promoting flow of the injected lift gas aroundthe base of diptube 582.

The embodiment depicted in FIG. 31 includes a single lift gas injectionvalve 578 (rather than multiple intermediate “unloading” valvestypically used in gas lift applications). Having a single lift gasinjection valve greatly simplifies the downhole system design and/ormechanics, thereby reducing the complexity and cost, and increasing thereliability of the overall system. Having a single lift gas injectionvalve, however, does require that the available gas lift system pressurebe sufficient to overcome and displace the heaviest fluid that mightfill the entire wellbore, or some other means to initially “unload” thewell in that event. Unloading valves may be used in some embodimentswhere the production wells are deep in the formation, for example,greater than 900 m deep, greater than 1000 m deep, or greater than 1500m deep in the formation.

In some embodiments, the chamber/well casing internal diameter ratio iskept as high as possible to maximize volumetric efficiency of thesystem. Keeping the chamber/well casing internal diameter ratio as highas possible may allow overall drawdown pressure and fluid productioninto the well to be maximized while pressure imposed on the heatedportion is minimized.

Lift gas injection valve 578 and the gas delivery and control system maybe designed to allow large volumes of gas to be injected into liftchamber 574 in a relatively short period of time to maximize theefficiency and minimize the time period for fluid evacuation. This mayallow liquid fallback in conduit 570 to be decreased (or minimized)while overall well fluid production potential is increased (ormaximized).

Various methods may be used to allow control of lift gas injection valve578 and the amount of gas injected during each lift cycle. Lift gasinjection valve 578 may be designed to be self-controlled, sensitive toeither lift chamber pressure or casing pressure. That is, lift gasinjection valve 578 may be similar to tubing pressure-operated or casingpressure-operated valves routinely used in conventional oilfield gaslift applications. Alternatively, lift gas injection valve 578 may becontrolled from the surface via either electric or hydraulic signal.These methods may be supplemented by additional controls that regulatethe rate and/or pressure at which lift gas is injected into annulus 552at surface 550. Other design and/or installation options for chamberlift systems (for example, types of conduit connections and/or method ofinstallation) may be chosen from a range of approaches known in the art.

FIG. 32 illustrates an embodiment of a chamber lift system that includesan additional parallel production conduit. Conduit 584 may allowcontinual flow of produced gas and/or vapor, bypassing lift chamber 574.Bypassing lift chamber 574 may avoid passing large volumes of gas and/orvapor through the lift chamber, which may reduce the efficiency of thesystem when the volumes of gas and/or vapor are large. In thisembodiment, the lift chamber evacuates any liquids from the wellaccumulating in sump 558 that do not flow from the well along with thegas/vapor phases. Sump 558 would aid the natural separation of liquidsfor more efficient operation.

FIG. 33 depicts an embodiment of a chamber lift system includinginjection gas supply conduit 586 from surface 550 down to lift gasinjection valve 578. There may be some advantages to this arrangement(for example, relating to wellbore integrity and/or barrier issues)compared to use of the casing annulus to transport the injection gas.While lift gas injection valve 578 is positioned downhole for control,this configuration may also facilitate the alternative option to controlthe lift gas injection entirely from surface 550. Controlling the liftgas injection entirely from surface 550 may eliminate the need fordownhole injection valve 578 and reduce the need for and/or costsassociated with wellbore intervention. Providing a separate lift gasconduit also permits the annulus around the production tubulars to bekept at a low pressure, or even under a vacuum, thus decreasing heattransfer from the production tubulars. This reduces condensation inconduit 584 and thus reflux back into heated portion 536.

FIG. 34 depicts an embodiment of a chamber lift system with anadditional check valve located at the top of the lift chamber/diptube.Check valve 588 may be retrieved separately via wireline or other meansto reduce maintenance and reduce the complexity and/or cost associatedwith well intervention. Check valve 588 may inhibit liquid fallback fromconduit 570 from returning to lift chamber 574 between lift cycles. Inaddition, check valve 588 may allow lift chamber 574 to be evacuated bydisplacing the chamber fluids and/or liquids only into the base ofconduit 570 (the conduit remains full of fluid between cycles),potentially optimizing injection gas usage and energy. In someembodiments, the injection gas tubing pressure is bled down betweeninjection cycles in this displacement mode to allow maximum drawdownpressure to be achieved with the surface injection gas control depictedin FIG. 34.

As depicted in FIG. 34, the downhole lift gas injection valve has beeneliminated, and injection gas control valve 590 is located above surface550. In some embodiments, the downhole valve is used in addition to orin lieu of injection gas control valve 590. Using the downhole controlvalve along with injection gas control valve 590 may allow the injectiongas tubing pressure to be retained in the displacement cycle mode.

FIG. 35 depicts an embodiment of a chamber lift system that allowsmixing of the gas/vapor stream into conduit 570 (without a separateconduit for gas and/or vapor), while bypassing lift chamber 574.Additional gas/vapor vent 568′ equipped with additional check valve 576′may allow continuous production of the gas/vapor phase fluids intoconduit 570 above lift chamber 574 between lift cycles. Check valve 576′may be separately retrievable as previously described for the otheroperating components. The embodiment depicted in FIG. 35 may allowsimplification of the downhole equipment arrangement through eliminationof a separate conduit for gas/vapor production. In some embodiments,lift gas injection is controlled via downhole gas injection valve 592.In certain embodiments, lift gas injection is controlled at surface 550.

FIG. 36 depicts an embodiment of a chamber lift system with checkvalve/vent assembly 594 below packer/reflux seal assembly 572,eliminating the flow through the packer/reflux seal assembly. With checkvalve/vent assembly 594 below packer/reflux seal assembly 572, thegas/vapor stream bypasses lift chamber 574 while retaining the single,comingled production stream to surface 550. Check valve 594 may beindependently retrievable, as previously described.

As depicted in FIG. 36, diptube 582 may be an integral part of conduit570 and lift chamber 574. With diptube 582 an integral part of conduit570 and lift chamber 574, check valve 576 at the bottom of the liftchamber may be more easily accessed (for example, via non-rigintervention methods including, but not limited to, wireline and coiltubing), and a larger diptube diameter may be used for higherliquid/fluid volumes. The retrievable diptube arrangement, as previouslydescribed, may be applied here as well, depending upon specific wellrequirements.

FIG. 37 depicts an embodiment of a chamber lift system with a separateflowpath to surface 550 for the gas/vapor phase of the production streamvia a concentric conduit approach similar to that described previouslyfor the rod pumping system concepts. This embodiment eliminates the needfor a check valve/vent system to commingle the gas/vapor stream into theproduction tubing with the liquid stream from the chamber as depicted inFIGS. 35 and 36 while including advantages of the concentric innerconduit 544 and outer conduit 546 depicted in FIGS. 28-30.

FIG. 38 depicts an embodiment of a chamber lift system with gas/vaporshroud 566 extending down into the sump 558. Gas/vapor shroud 566 andsump 558 provide the same advantages as described with respect to FIG.30.

Temperature limited heaters may be in configurations and/or may includematerials that provide automatic temperature limiting properties for theheater at certain temperatures. In certain embodiments, ferromagneticmaterials are used in temperature limited heaters. Ferromagneticmaterial may self-limit temperature at or near the Curie temperature ofthe material to provide a reduced amount of heat at or near the Curietemperature when a time-varying current is applied to the material. Incertain embodiments, the ferromagnetic material self-limits temperatureof the temperature limited heater at a selected temperature that isapproximately the Curie temperature. In certain embodiments, theselected temperature is within about 35° C., within about 25° C., withinabout 20° C., or within about 10° C. of the Curie temperature. Incertain embodiments, ferromagnetic materials are coupled with othermaterials (for example, highly conductive materials, high strengthmaterials, corrosion resistant materials, or combinations thereof) toprovide various electrical and/or mechanical properties. Some parts ofthe temperature limited heater may have a lower resistance (caused bydifferent geometries and/or by using different ferromagnetic and/ornon-ferromagnetic materials) than other parts of the temperature limitedheater. Having parts of the temperature limited heater with variousmaterials and/or dimensions allows for tailoring the desired heat outputfrom each part of the heater.

Temperature limited heaters may be more reliable than other heaters.Temperature limited heaters may be less apt to break down or fail due tohot spots in the formation. In some embodiments, temperature limitedheaters allow for substantially uniform heating of the formation. Insome embodiments, temperature limited heaters are able to heat theformation more efficiently by operating at a higher average heat outputalong the entire length of the heater. The temperature limited heateroperates at the higher average heat output along the entire length ofthe heater because power to the heater does not have to be reduced tothe entire heater, as is the case with typical constant wattage heaters,if a temperature along any point of the heater exceeds, or is about toexceed, a maximum operating temperature of the heater. Heat output fromportions of a temperature limited heater approaching a Curie temperatureof the heater automatically reduces without controlled adjustment of thetime-varying current applied to the heater. The heat outputautomatically reduces due to changes in electrical properties (forexample, electrical resistance) of portions of the temperature limitedheater. Thus, more power is supplied by the temperature limited heaterduring a greater portion of a heating process.

In certain embodiments, the system including temperature limited heatersinitially provides a first heat output and then provides a reduced(second heat output) heat output, near, at, or above the Curietemperature of an electrically resistive portion of the heater when thetemperature limited heater is energized by a time-varying current. Thefirst heat output is the heat output at temperatures below which thetemperature limited heater begins to self-limit. In some embodiments,the first heat output is the heat output at a temperature 50° C., 75°C., 100° C., or 125° C. below the Curie temperature of the ferromagneticmaterial in the temperature limited heater.

The temperature limited heater may be energized by time-varying current(alternating current or modulated direct current) supplied at thewellhead. The wellhead may include a power source and other components(for example, modulation components, transformers, and/or capacitors)used in supplying power to the temperature limited heater. Thetemperature limited heater may be one of many heaters used to heat aportion of the formation.

In certain embodiments, the temperature limited heater includes aconductor that operates as a skin effect or proximity effect heater whentime-varying current is applied to the conductor. The skin effect limitsthe depth of current penetration into the interior of the conductor. Forferromagnetic materials, the skin effect is dominated by the magneticpermeability of the conductor. The relative magnetic permeability offerromagnetic materials is typically between 10 and 1000 (for example,the relative magnetic permeability of ferromagnetic materials istypically at least 10 and may be at least 50, 100, 500, 1000 orgreater). As the temperature of the ferromagnetic material is raisedabove the Curie temperature and/or as the applied electrical current isincreased, the magnetic permeability of the ferromagnetic materialdecreases substantially and the skin depth expands rapidly (for example,the skin depth expands as the inverse square root of the magneticpermeability). The reduction in magnetic permeability results in adecrease in the AC or modulated DC resistance of the conductor near, at,or above the Curie temperature and/or as the applied electrical currentis increased. When the temperature limited heater is powered by asubstantially constant current source, portions of the heater thatapproach, reach, or are above the Curie temperature may have reducedheat dissipation. Sections of the temperature limited heater that arenot at or near the Curie temperature may be dominated by skin effectheating that allows the heater to have high heat dissipation due to ahigher resistive load.

Curie temperature heaters have been used in soldering equipment, heatersfor medical applications, and heating elements for ovens (for example,pizza ovens). Some of these uses are disclosed in U.S. Pat. Nos.5,579,575 to Lamome et al.; 5,065,501 to Henschen et al.; and 5,512,732to Yagnik et al., all of which are incorporated by reference as if fullyset forth herein. U.S. Pat. No. 4,849,611 to Whitney et al., which isincorporated by reference as if fully set forth herein, describes aplurality of discrete, spaced-apart heating units including a reactivecomponent, a resistive heating component, and a temperature responsivecomponent.

An advantage of using the temperature limited heater to heathydrocarbons in the formation is that the conductor is chosen to have aCurie temperature in a desired range of temperature operation. Operationwithin the desired operating temperature range allows substantial heatinjection into the formation while maintaining the temperature of thetemperature limited heater, and other equipment, below design limittemperatures. Design limit temperatures are temperatures at whichproperties such as corrosion, creep, and/or deformation are adverselyaffected. The temperature limiting properties of the temperature limitedheater inhibits overheating or burnout of the heater adjacent to lowthermal conductivity “hot spots” in the formation. In some embodiments,the temperature limited heater is able to lower or control heat outputand/or withstand heat at temperatures above 25° C., 37° C., 100° C.,250° C., 500° C., 700° C., 800° C., 900° C., or higher up to 1131° C.,depending on the materials used in the heater.

The temperature limited heater allows for more heat injection into theformation than constant wattage heaters because the energy input intothe temperature limited heater does not have to be limited toaccommodate low thermal conductivity regions adjacent to the heater. Forexample, in Green River oil shale there is a difference of at least afactor of 3 in the thermal conductivity of the lowest richness oil shalelayers and the highest richness oil shale layers. When heating such aformation, substantially more heat is transferred to the formation withthe temperature limited heater than with the conventional heater that islimited by the temperature at low thermal conductivity layers. The heatoutput along the entire length of the conventional heater needs toaccommodate the low thermal conductivity layers so that the heater doesnot overheat at the low thermal conductivity layers and burn out. Theheat output adjacent to the low thermal conductivity layers that are athigh temperature will reduce for the temperature limited heater, but theremaining portions of the temperature limited heater that are not athigh temperature will still provide high heat output. Because heatersfor heating hydrocarbon formations typically have long lengths (forexample, at least 10 m, 100 m, 300 m, 500 m, 1 km or more up to about 10km), the majority of the length of the temperature limited heater may beoperating below the Curie temperature while only a few portions are ator near the Curie temperature of the temperature limited heater.

The use of temperature limited heaters allows for efficient transfer ofheat to the formation. Efficient transfer of heat allows for reductionin time needed to heat the formation to a desired temperature. Forexample, in Green River oil shale, pyrolysis typically requires 9.5years to 10 years of heating when using a 12 m heater well spacing withconventional constant wattage heaters. For the same heater spacing,temperature limited heaters may allow a larger average heat output whilemaintaining heater equipment temperatures below equipment design limittemperatures. Pyrolysis in the formation may occur at an earlier timewith the larger average heat output provided by temperature limitedheaters than the lower average heat output provided by constant wattageheaters. For example, in Green River oil shale, pyrolysis may occur in 5years using temperature limited heaters with a 12 m heater well spacing.Temperature limited heaters counteract hot spots due to inaccurate wellspacing or drilling where heater wells come too close together. Incertain embodiments, temperature limited heaters allow for increasedpower output over time for heater wells that have been spaced too farapart, or limit power output for heater wells that are spaced too closetogether. Temperature limited heaters also supply more power in regionsadjacent the overburden and underburden to compensate for temperaturelosses in these regions.

Temperature limited heaters may be advantageously used in many types offormations. For example, in tar sands formations or relatively permeableformations containing heavy hydrocarbons, temperature limited heatersmay be used to provide a controllable low temperature output forreducing the viscosity of fluids, mobilizing fluids, and/or enhancingthe radial flow of fluids at or near the wellbore or in the formation.Temperature limited heaters may be used to inhibit excess coke formationdue to overheating of the near wellbore region of the formation.

The use of temperature limited heaters, in some embodiments, eliminatesor reduces the need for expensive temperature control circuitry. Forexample, the use of temperature limited heaters eliminates or reducesthe need to perform temperature logging and/or the need to use fixedthermocouples on the heaters to monitor potential overheating at hotspots.

In certain embodiments, phase transformation (for example, crystallinephase transformation or a change in the crystal structure) of materialsused in a temperature limited heater change the selected temperature atwhich the heater self-limits. Ferromagnetic material used in thetemperature limited heater may have a phase transformation (for example,a transformation from ferrite to austenite) that decreases the magneticpermeability of the ferromagnetic material. This reduction in magneticpermeability is similar to reduction in magnetic permeability due to themagnetic transition of the ferromagnetic material at the Curietemperature. The Curie temperature is the magnetic transitiontemperature of the ferrite phase of the ferromagnetic material. Thereduction in magnetic permeability results in a decrease in the AC ormodulated DC resistance of the temperature limited heater near, at, orabove the temperature of the phase transformation and/or the Curietemperature of the ferromagnetic material.

The phase transformation of the ferromagnetic material may occur over atemperature range. The temperature range of the phase transformationdepends on the ferromagnetic material and may vary, for example, over arange of about 20° C. to a range of about 200° C. Because the phasetransformation takes place over a temperature range, the reduction inthe magnetic permeability due to the phase transformation takes placeover the temperature range. The reduction in magnetic permeability mayalso occur irregularly over the temperature range of the phasetransformation. In some embodiments, the phase transformation back tothe lower temperature phase of the ferromagnetic material is slower thanthe phase transformation to the higher temperature phase (for example,the transition from austenite back to ferrite is slower than thetransition from ferrite to austenite). The slower phase transformationback to the lower temperature phase may cause irregular operation of theheater at or near the phase transformation temperature range.

In some embodiments, the phase transformation temperature range overlapswith the reduction in the magnetic permeability when the temperatureapproaches the Curie temperature of the ferromagnetic material. Theoverlap may produce a slower drop in electrical resistance versustemperature than if the reduction in magnetic permeability is solely dueto the temperature approaching the Curie temperature. The overlap mayalso produce irregular behavior of the temperature limited heater nearthe Curie temperature and/or in the phase transformation temperaturerange.

In certain embodiments, alloy additions are made to the ferromagneticmaterial to adjust the temperature range of the phase transformation.For example, adding carbon to the ferromagnetic material may increasethe phase transformation temperature range and lower the onsettemperature of the phase transformation. Adding titanium to theferromagnetic material may increase the onset temperature of the phasetransformation and decrease the phase transformation temperature range.Alloy compositions may be adjusted to provide desired Curie temperatureand phase transformation properties for the ferromagnetic material. Thealloy composition of the ferromagnetic material may be chosen based ondesired properties for the ferromagnetic material (such as, but notlimited to, magnetic permeability transition temperature or temperaturerange, resistance versus temperature profile, or power output). Additionof titanium may allow higher Curie temperatures to be obtained whenadding cobalt to 410 stainless steel by raising the ferrite to austenitephase transformation temperature range to a temperature range that isabove, or well above, the Curie temperature of the ferromagneticmaterial.

In certain embodiments, the temperature limited heater is deformationtolerant. Localized movement of material in the wellbore may result inlateral stresses on the heater that could deform its shape. Locationsalong a length of the heater at which the wellbore approaches or closeson the heater may be hot spots where a standard heater overheats and hasthe potential to burn out. These hot spots may lower the yield strengthand creep strength of the metal, allowing crushing or deformation of theheater. The temperature limited heater may be formed with S curves (orother non-linear shapes) that accommodate deformation of the temperaturelimited heater without causing failure of the heater.

In some embodiments, temperature limited heaters are more economical tomanufacture or make than standard heaters. Typical ferromagneticmaterials include iron, carbon steel, or ferritic stainless steel. Suchmaterials are inexpensive as compared to nickel-based heating alloys(such as nichrome, Kanthal™ (Bulten-Kanthal A B, Sweden), and/or LOHM™(Driver-Harris Company, Harrison, N.J., U.S.A.)) typically used ininsulated conductor (mineral insulated cable) heaters. In one embodimentof the temperature limited heater, the temperature limited heater ismanufactured in continuous lengths as an insulated conductor heater tolower costs and improve reliability.

In some embodiments, the temperature limited heater is placed in theheater well using a coiled tubing rig. A heater that can be coiled on aspool may be manufactured by using metal such as ferritic stainlesssteel (for example, 409 stainless steel) that is welded using electricalresistance welding (ERW). To form a heater section, a metal strip from aroll is passed through a first former where it is shaped into a tubularand then longitudinally welded using ERW. The tubular is passed througha second former where a conductive strip (for example, a copper strip)is applied, drawn down tightly on the tubular through a die, andlongitudinally welded using ERW. A sheath may be formed bylongitudinally welding a support material (for example, steel such as347H or 347HH) over the conductive strip material. The support materialmay be a strip rolled over the conductive strip material. An overburdensection of the heater may be formed in a similar manner.

FIG. 39 depicts an embodiment of a device for longitudinal welding of atubular using ERW. Metal strip 596 is shaped into tubular form as itpasses through ERW coil 598. Metal strip 596 is then welded into atubular inside shield 600. As metal strip 596 is joined inside shield600, inert gas (for example, argon or another suitable welding gas) isprovided inside the forming tubular by gas inlets 602. Flushing thetubular with inert gas inhibits oxidation of the tubular as it isformed. Shield 600 may have window 604. Window 604 allows an operator tovisually inspect the welding process. Tubular 606 is formed by thewelding process.

In certain embodiments, the overburden section uses a non-ferromagneticmaterial such as 304 stainless steel or 316 stainless steel instead of aferromagnetic material. The heater section and overburden section may becoupled using standard techniques such as butt welding using an orbitalwelder. In some embodiments, the overburden section material (thenon-ferromagnetic material) may be pre-welded to the ferromagneticmaterial before rolling. The pre-welding may eliminate the need for aseparate coupling step (for example, butt welding). In an embodiment, aflexible cable (for example, a furnace cable such as a MGT 1000 furnacecable) may be pulled through the center after forming the tubularheater. An end bushing on the flexible cable may be welded to thetubular heater to provide an electrical current return path. The tubularheater, including the flexible cable, may be coiled onto a spool beforeinstallation into a heater well. In an embodiment, the temperaturelimited heater is installed using the coiled tubing rig. The coiledtubing rig may place the temperature limited heater in a deformationresistant container in the formation. The deformation resistantcontainer may be placed in the heater well using conventional methods.

In an embodiment, a Curie heater includes a furnace cable inside aferromagnetic conduit (for example, a ¾″ Schedule 80 446 stainless steelpipe). The ferromagnetic conduit may be clad with copper or anothersuitable conductive material. The ferromagnetic conduit may be placed ina deformation-tolerant conduit or deformation resistant container. Thedeformation-tolerant conduit may tolerate longitudinal deformation,radial deformation, and creep. The deformation-tolerant conduit may alsosupport the ferromagnetic conduit and furnace cable. Thedeformation-tolerant conduit may be selected based on creep and/orcorrosion resistance near or at the Curie temperature. In oneembodiment, the deformation-tolerant conduit is 1½″ Schedule 80 347Hstainless steel pipe (outside diameter of about 4.826 cm) or 1½″Schedule 160 347H stainless steel pipe (outside diameter of about 4.826cm).

The diameter and/or materials of the deformation-tolerant conduit mayvary depending on, for example, characteristics of the formation to beheated or desired heat output characteristics of the heater. In certainembodiments, air is removed from the annulus between thedeformation-tolerant conduit and the clad ferromagnetic conduit. Thespace between the deformation-tolerant conduit and the cladferromagnetic conduit may be flushed with a pressurized inert gas (forexample, helium, nitrogen, argon, or mixtures thereof). In someembodiments, the inert gas may include a small amount of hydrogen to actas a “getter” for residual oxygen. The inert gas may pass down theannulus from the surface, enter the inner diameter of the ferromagneticconduit through a small hole near the bottom of the heater, and flow upinside the ferromagnetic conduit. Removal of the air in the annulus mayreduce oxidation of materials in the heater (for example, thenickel-coated copper wires of the furnace cable) to provide a longerlife heater, especially at elevated temperatures. Thermal conductionbetween the furnace cable and the ferromagnetic conduit, and between theferromagnetic conduit and the deformation-tolerant conduit, may beimproved when the inert gas is helium. The pressurized inert gas in theannular space may also provide additional support for thedeformation-tolerant conduit against high formation pressures.Pressurized inert gas also inhibits arcing between metal conductors inthe annular space compared to inert gas at atmospheric pressure.

In certain embodiments, a thermally conductive fluid such as helium maybe placed inside void volumes of the temperature limited heater whereheat is transferred. Placing thermally conductive fluid inside voidvolumes of the temperature limited heater may improve thermal conductioninside the void volumes. Thermally conductive fluids include, but arenot limited to, gases that are thermally conductive, electricallyinsulating, and radiantly transparent. In certain embodiments, thermallyconductive fluid in the void volumes has a higher thermal conductivitythan air at standard temperature and pressure (STP) (0° C. and 101.325kPa). Radiantly transparent gases include gases with diatomic or singleatoms that do not absorb a significant amount of infrared energy. Incertain embodiments, thermally conductive fluids include helium and/orhydrogen. Thermally conductive fluids may also be thermally stable atoperating temperatures in the temperature limited heater so that thethermally conductive fluids do not thermally crack at operatingtemperature in the temperature limited heater.

Thermally conductive fluid may be placed inside a conductor, inside aconduit, and/or inside a jacket of a temperature limited heater. Thethermally conductive fluid may be placed in the space (the annulus)between one or more components (for example, conductor, conduit, orjacket) of the temperature limited heater. In some embodiments,thermally conductive fluid is placed in the space (the annulus) betweenthe temperature limited heater and a conduit.

In certain embodiments, air and/or other fluid in the space (theannulus) is displaced by a flow of thermally conductive fluid duringintroduction of the thermally conductive fluid into the space. In someembodiments, air and/or other fluid is removed (for example, vacuumed,flushed, or pumped out) from the space before introducing thermallyconductive fluid in the space. Reducing the partial pressure of oxygenin the space reduces the rate of oxidation of heater components in thespace. The thermally conductive fluid is introduced in a specific volumeand/or to a selected pressure in the space. Thermally conductive fluidmay be introduced such that the space has at least a minimum volumepercentage of thermally conductive fluid above a selected value. Incertain embodiments, the space has at least 50%, 75%, or 90% by volumeof thermally conductive fluid.

Placing thermally conductive fluid inside the space of the temperaturelimited heater increases thermal heat transfer in the space. Theincreased thermal heat transfer is caused by reducing resistance to heattransfer in the space with the thermally conductive fluid. Reducingresistance to heat transfer in the space allows for increased poweroutput from the temperature limited heater to the subsurface formation.Reducing the resistance to heat transfer inside the space with thethermally conductive fluid allows for smaller diameter electricalconductors (for example, a smaller diameter inner conductor, a smallerdiameter outer conductor, and/or a smaller diameter conduit), a largerouter radius (for example, a larger radius of a conduit or a jacket),and/or an increased space width. Reducing the diameter of electricalconductors reduces material costs. Increasing the outer radius of theconduit or the jacket and/or increasing the annulus space width providesadditional annular space. Additional annular space may accommodatedeformation of the conduit and/or the jacket without causing heaterfailure. Increasing the outer radius of the conduit or the jacket and/orincreasing the annulus width may provide additional annular space toprotect components (for example, spacers, connectors, and/or conduits)in the annulus.

As the annular width of the temperature limited heater is increased,however, greater heat transfer is needed across the annular space tomaintain good heat output properties for the heater. In someembodiments, especially for low temperature heaters, radiative heattransfer is minimally effective in transferring heat across the annularspace of the heater. Conductive heat transfer in the annular space isimportant in such embodiments to maintain good heat output propertiesfor the heater. A thermally conductive fluid provides increased heattransfer across the annular space.

In certain embodiments, the thermally conductive fluid located in thespace is also electrically insulating to inhibit arcing betweenconductors in the temperature limited heater. Arcing across the space orgap is a problem with longer heaters that require higher operatingvoltages. Arcing may be a problem with shorter heaters and/or at lowervoltages depending on the operating conditions of the heater. Increasingthe pressure of the fluid in the space increases the spark gap breakdownvoltage in the space and inhibits arcing across the space. Certaingases, such as SF₆ or N₂, have greater resistance to electricalbreakdown but have lower thermal conductivities than helium or hydrogenbecause of their higher molecular weights. Thus, gases such as SF₆ or N₂may be less desirable in some embodiments.

Pressure of thermally conductive fluid in the space may be increased toa pressure between 200 kPa and 60,000 kPa, between 500 kPa and 50,000kPa, between 700 kPa and 45,000 kPa, or between 1000 kPa and 40,000 kPa.In an embodiment, the pressure of the thermally conductive fluid isincreased to at least 700 kPa or at least 1000 kPa. In certainembodiments, the pressure of the thermally conductive fluid needed toinhibit arcing across the space depends on the temperature in the space.Electrons may track along surfaces (for example, insulators, connectors,or shields) in the space and cause arcing or electrical degradation ofthe surfaces. High pressure fluid in the space may inhibit electrontracking along surfaces in the space. Helium has about one-seventh thebreakdown voltage of air at atmospheric pressure. Thus, higher pressuresof helium (for example, 7 atm (707 kPa) or greater of helium) may beused to compensate for the lower breakdown voltage of helium as comparedto air.

Temperature limited heaters may be used for heating hydrocarbonformations including, but not limited to, oil shale formations, coalformations, tar sands formations, and formations with heavy viscousoils. Temperature limited heaters may also be used in the field ofenvironmental remediation to vaporize or destroy soil contaminants.Embodiments of temperature limited heaters may be used to heat fluids ina wellbore or sub-sea pipeline to inhibit deposition of paraffin orvarious hydrates. In some embodiments, a temperature limited heater isused for solution mining a subsurface formation (for example, an oilshale or a coal formation). In certain embodiments, a fluid (forexample, molten salt) is placed in a wellbore and heated with atemperature limited heater to inhibit deformation and/or collapse of thewellbore. In some embodiments, the temperature limited heater isattached to a sucker rod in the wellbore or is part of the sucker roditself. In some embodiments, temperature limited heaters are used toheat a near wellbore region to reduce near wellbore oil viscosity duringproduction of high viscosity crude oils and during transport of highviscosity oils to the surface. In some embodiments, a temperaturelimited heater enables gas lifting of a viscous oil by lowering theviscosity of the oil without coking the oil. Temperature limited heatersmay be used in sulfur transfer lines to maintain temperatures betweenabout 110° C. and about 130° C.

Certain embodiments of temperature limited heaters may be used inchemical or refinery processes at elevated temperatures that requirecontrol in a narrow temperature range to inhibit unwanted chemicalreactions or damage from locally elevated temperatures. Someapplications may include, but are not limited to, reactor tubes, cokers,and distillation towers. Temperature limited heaters may also be used inpollution control devices (for example, catalytic converters, andoxidizers) to allow rapid heating to a control temperature withoutcomplex temperature control circuitry. Additionally, temperature limitedheaters may be used in food processing to avoid damaging food withexcessive temperatures. Temperature limited heaters may also be used inthe heat treatment of metals (for example, annealing of weld joints).Temperature limited heaters may also be used in floor heaters,cauterizers, and/or various other appliances. Temperature limitedheaters may be used with biopsy needles to destroy tumors by raisingtemperatures in vivo.

Some embodiments of temperature limited heaters may be useful in certaintypes of medical and/or veterinary devices. For example, a temperaturelimited heater may be used to therapeutically treat tissue in a human oran animal. A temperature limited heater for a medical or veterinarydevice may have ferromagnetic material including a palladium-copperalloy with a Curie temperature of about 50° C. A high frequency (forexample, a frequency greater than about 1 MHz) may be used to power arelatively small temperature limited heater for medical and/orveterinary use.

The ferromagnetic alloy or ferromagnetic alloys used in the temperaturelimited heater determine the Curie temperature of the heater. Curietemperature data for various metals is listed in “American Institute ofPhysics Handbook,” Second Edition, McGraw-Hill, pages 5-170 through5-176. Ferromagnetic conductors may include one or more of theferromagnetic elements (iron, cobalt, and nickel) and/or alloys of theseelements. In some embodiments, ferromagnetic conductors includeiron-chromium (Fe—Cr) alloys that contain tungsten (W) (for example,HCM12A and SAVE12 (Sumitomo Metals Co., Japan) and/or iron alloys thatcontain chromium (for example, Fe—Cr alloys, Fe—Cr—W alloys, Fe—Cr—V(vanadium) alloys, and Fe—Cr—Nb (Niobium) alloys). Of the three mainferromagnetic elements, iron has a Curie temperature of approximately770° C.; cobalt (Co) has a Curie temperature of approximately 1131° C.;and nickel has a Curie temperature of approximately 358° C. Aniron-cobalt alloy has a Curie temperature higher than the Curietemperature of iron. For example, iron-cobalt alloy with 2% by weightcobalt has a Curie temperature of approximately 800° C.; iron-cobaltalloy with 12% by weight cobalt has a Curie temperature of approximately900° C.; and iron-cobalt alloy with 20% by weight cobalt has a Curietemperature of approximately 950° C. Iron-nickel alloy has a Curietemperature lower than the Curie temperature of iron: For example,iron-nickel alloy with 20% by weight nickel has a Curie temperature ofapproximately 720° C., and iron-nickel alloy with 60% by weight nickelhas a Curie temperature of approximately 560° C.

Some non-ferromagnetic elements used as alloys raise the Curietemperature of iron. For example, an iron-vanadium alloy with 5.9% byweight vanadium has a Curie temperature of approximately 815° C. Othernon-ferromagnetic elements (for example, carbon, aluminum, copper,silicon, and/or chromium) may be alloyed with iron or otherferromagnetic materials to lower the Curie temperature.Non-ferromagnetic materials that raise the Curie temperature may becombined with non-ferromagnetic materials that lower the Curietemperature and alloyed with iron or other ferromagnetic materials toproduce a material with a desired Curie temperature and other desiredphysical and/or chemical properties. In some embodiments, the Curietemperature material is a ferrite such as NiFe₂O₄. In other embodiments,the Curie temperature material is a binary compound such as FeNi₃ orFe₃Al.

Certain embodiments of temperature limited heaters may include more thanone ferromagnetic material. Such embodiments are within the scope ofembodiments described herein if any conditions described herein apply toat least one of the ferromagnetic materials in the temperature limitedheater.

Ferromagnetic properties generally decay as the Curie temperature isapproached. The “Handbook of Electrical Heating for Industry” by C.James Erickson (IEEE Press, 1995) shows a typical curve for 1% carbonsteel (steel with 1% carbon by weight). The loss of magneticpermeability starts at temperatures above 650° C. and tends to becomplete when temperatures exceed 730° C. Thus, the self-limitingtemperature may be somewhat below the actual Curie temperature of theferromagnetic conductor. The skin depth for current flow in 1% carbonsteel is 0.132 cm at room temperature and increases to 0.445 cm at 720°C. From 720° C. to 730° C., the skin depth sharply increases to over 2.5cm. Thus, a temperature limited heater embodiment using 1% carbon steelbegins to self-limit between 650° C. and 730° C.

Skin depth generally defines an effective penetration depth oftime-varying current into the conductive material. In general, currentdensity decreases exponentially with distance from an outer surface tothe center along the radius of the conductor. The depth at which thecurrent density is approximately 1/e of the surface current density iscalled the skin depth. For a solid cylindrical rod with a diameter muchgreater than the penetration depth, or for hollow cylinders with a wallthickness exceeding the penetration depth, the skin depth, δ, is:δ=1981.5*(ρ/(μ*f)^(1/2);  (2)in which:

-   -   δ=skin depth in inches;    -   ρ=resistivity at operating temperature (ohm-cm);    -   μ=relative magnetic permeability; and    -   f=frequency (Hz).

EQN. 2 is obtained from “Handbook of Electrical Heating for Industry” byC. James Erickson (IEEE Press, 1995). For most metals, resistivity (ρ)increases with temperature. The relative magnetic permeability generallyvaries with temperature and with current. Additional equations may beused to assess the variance of magnetic permeability and/or skin depthon both temperature and/or current. The dependence of μ on currentarises from the dependence of μ on the magnetic field.

Materials used in the temperature limited heater may be selected toprovide a desired turndown ratio. Turndown ratios of at least 1.1:1,2:1, 3:1, 4:1, 5:1, 10:1, 30:1, or 50:1 may be selected for temperaturelimited heaters. Larger turndown ratios may also be used. A selectedturndown ratio may depend on a number of factors including, but notlimited to, the type of formation in which the temperature limitedheater is located (for example, a higher turndown ratio may be used foran oil shale formation with large variations in thermal conductivitybetween rich and lean oil shale layers) and/or a temperature limit ofmaterials used in the wellbore (for example, temperature limits ofheater materials). In some embodiments, the turndown ratio is increasedby coupling additional copper or another good electrical conductor tothe ferromagnetic material (for example, adding copper to lower theresistance above the Curie temperature).

The temperature limited heater may provide a maximum heat output (poweroutput) below the Curie temperature of the heater. In certainembodiments, the maximum heat output is at least 400 W/m (Watts permeter), 600 W/m, 700 W/m, 800 W/m, or higher up to 2000 W/m. Thetemperature limited heater reduces the amount of heat output by asection of the heater when the temperature of the section of the heaterapproaches or is above the Curie temperature. The reduced amount of heatmay be substantially less than the heat output below the Curietemperature. In some embodiments, the reduced amount of heat is at most400 W/m, 200 W/m, 100 W/m or may approach 0 W/m.

In certain embodiments, the temperature limited heater operatessubstantially independently of the thermal load on the heater in acertain operating temperature range. “Thermal load” is the rate thatheat is transferred from a heating system to its surroundings. It is tobe understood that the thermal load may vary with temperature of thesurroundings and/or the thermal conductivity of the surroundings. In anembodiment, the temperature limited heater operates at or above theCurie temperature of the temperature limited heater such that theoperating temperature of the heater increases at most by 3° C., 2° C.,1.5° C., 1° C., or 0.5° C. for a decrease in thermal load of 1 W/mproximate to a portion of the heater. In certain embodiments, thetemperature limited heater operates in such a manner at a relativelyconstant current.

The AC or modulated DC resistance and/or the heat output of thetemperature limited heater may decrease as the temperature approachesthe Curie temperature and decrease sharply near or above the Curietemperature due to the Curie effect. In certain embodiments, the valueof the electrical resistance or heat output above or near the Curietemperature is at most one-half of the value of electrical resistance orheat output at a certain point below the Curie temperature. In someembodiments, the heat output above or near the Curie temperature is atmost 90%, 70%, 50%, 30%, 20%, 10%, or less (down to 1%) of the heatoutput at a certain point below the Curie temperature (for example, 30°C. below the Curie temperature, 40° C. below the Curie temperature, 50°C. below the Curie temperature, or 100° C. below the Curie temperature).In certain embodiments, the electrical resistance above or near theCurie temperature decreases to 80%, 70%, 60%, 50%, or less (down to 1%)of the electrical resistance at a certain point below the Curietemperature (for example, 30° C. below the Curie temperature, 40° C.below the Curie temperature, 50° C. below the Curie temperature, or 100°C. below the Curie temperature).

In some embodiments, AC frequency is adjusted to change the skin depthof the ferromagnetic material. For example, the skin depth of 1% carbonsteel at room temperature is 0.132 cm at 60 Hz, 0.0762 cm at 180 Hz, and0.046 cm at 440 Hz. Since heater diameter is typically larger than twicethe skin depth, using a higher frequency (and thus a heater with asmaller diameter) reduces heater costs. For a fixed geometry, the higherfrequency results in a higher turndown ratio. The turndown ratio at ahigher frequency is calculated by multiplying the turndown ratio at alower frequency by the square root of the higher frequency divided bythe lower frequency. In some embodiments, a frequency between 100 Hz and1000 Hz, between 140 Hz and 200 Hz, or between 400 Hz and 600 Hz is used(for example, 180 Hz, 540 Hz, or 720 Hz). In some embodiments, highfrequencies may be used. The frequencies may be greater than 1000 Hz.

To maintain a substantially constant skin depth until the Curietemperature of the temperature limited heater is reached, the heater maybe operated at a lower frequency when the heater is cold and operated ata higher frequency when the heater is hot. Line frequency heating isgenerally favorable, however, because there is less need for expensivecomponents such as power supplies, transformers, or current modulatorsthat alter frequency. Line frequency is the frequency of a generalsupply of current. Line frequency is typically 60 Hz, but may be 50 Hzor another frequency depending on the source for the supply of thecurrent. Higher frequencies may be produced using commercially availableequipment such as solid state variable frequency power supplies.Transformers that convert three-phase power to single-phase power withthree times the frequency are commercially available. For example, highvoltage three-phase power at 60 Hz may be transformed to single-phasepower at 180 Hz and at a lower voltage. Such transformers are lessexpensive and more energy efficient than solid state variable frequencypower supplies. In certain embodiments, transformers that convertthree-phase power to single-phase power are used to increase thefrequency of power supplied to the temperature limited heater.

In certain embodiments, modulated DC (for example, chopped DC, waveformmodulated DC, or cycled DC) may be used for providing electrical powerto the temperature limited heater. A DC modulator or DC chopper may becoupled to a DC power supply to provide an output of modulated directcurrent. In some embodiments, the DC power supply may include means formodulating DC. One example of a DC modulator is a DC-to-DC convertersystem. DC-to-DC converter systems are generally known in the art. DC istypically modulated or chopped into a desired waveform. Waveforms for DCmodulation include, but are not limited to, square-wave, sinusoidal,deformed sinusoidal, deformed square-wave, triangular, and other regularor irregular waveforms.

The modulated DC waveform generally defines the frequency of themodulated DC. Thus, the modulated DC waveform may be selected to providea desired modulated DC frequency. The shape and/or the rate ofmodulation (such as the rate of chopping) of the modulated DC waveformmay be varied to vary the modulated DC frequency. DC may be modulated atfrequencies that are higher than generally available AC frequencies. Forexample, modulated DC may be provided at frequencies of at least 1000Hz. Increasing the frequency of supplied current to higher valuesadvantageously increases the turndown ratio of the temperature limitedheater.

In certain embodiments, the modulated DC waveform is adjusted or alteredto vary the modulated DC frequency. The DC modulator may be able toadjust or alter the modulated DC waveform at any time during use of thetemperature limited heater and at high currents or voltages. Thus,modulated DC provided to the temperature limited heater is not limitedto a single frequency or even a small set of frequency values. Waveformselection using the DC modulator typically allows for a wide range ofmodulated DC frequencies and for discrete control of the modulated DCfrequency. Thus, the modulated DC frequency is more easily set at adistinct value whereas AC frequency is generally limited to multiples ofthe line frequency. Discrete control of the modulated DC frequencyallows for more selective control over the turndown ratio of thetemperature limited heater. Being able to selectively control theturndown ratio of the temperature limited heater allows for a broaderrange of materials to be used in designing and constructing thetemperature limited heater.

In certain embodiments, electrical power for the temperature limitedheater is initially supplied using non-modulated DC or very lowfrequency modulated DC. Using DC, or low frequency DC, at earlier timesof heating reduces inefficiencies associated with higher frequencies. DCand/or low frequency modulated DC may also be cheaper to use duringinitial heating times. After a selected temperature is reached in atemperature limited heater; modulated DC, higher frequency modulated DC,or AC is used for providing electrical power to the temperature limitedheater so that the heat output will decrease near, at, or above theCurie temperature.

In some embodiments, the modulated DC frequency or the AC frequency isadjusted to compensate for changes in properties (for example,subsurface conditions such as temperature or pressure) of thetemperature limited heater during use. The modulated DC frequency or theAC frequency provided to the temperature limited heater is varied basedon assessed downhole conditions. For example, as the temperature of thetemperature limited heater in the wellbore increases, it may beadvantageous to increase the frequency of the current provided to theheater, thus increasing the turndown ratio of the heater. In anembodiment, the downhole temperature of the temperature limited heaterin the wellbore is assessed.

In certain embodiments, the modulated DC frequency, or the AC frequency,is varied to adjust the turndown ratio of the temperature limitedheater. The turndown ratio may be adjusted to compensate for hot spotsoccurring along a length of the temperature limited heater. For example,the turndown ratio is increased because the temperature limited heateris getting too hot in certain locations. In some embodiments, themodulated DC frequency, or the AC frequency, are varied to adjust aturndown ratio without assessing a subsurface condition.

At or near the Curie temperature of the ferromagnetic material, arelatively small change in voltage may cause a relatively large changein current to the load. The relatively small change in voltage mayproduce problems in the power supplied to the temperature limitedheater, especially at or near the Curie temperature. The problemsinclude, but are not limited to, reducing the power factor, tripping acircuit breaker, and/or blowing a fuse. In some cases, voltage changesmay be caused by a change in the load of the temperature limited heater.In certain embodiments, an electrical current supply (for example, asupply of modulated DC or AC) provides a relatively constant amount ofcurrent that does not substantially vary with changes in load of thetemperature limited heater. In an embodiment, the electrical currentsupply provides an amount of electrical current that remains within 15%,within 10%, within 5%, or within 2% of a selected constant current valuewhen a load of the temperature limited heater changes.

Temperature limited heaters may generate an inductive load. Theinductive load is due to some applied electrical current being used bythe ferromagnetic material to generate a magnetic field in addition togenerating a resistive heat output. As downhole temperature changes inthe temperature limited heater, the inductive load of the heater changesdue to changes in the ferromagnetic properties of ferromagneticmaterials in the heater with temperature. The inductive load of thetemperature limited heater may cause a phase shift between the currentand the voltage applied to the heater.

A reduction in actual power applied to the temperature limited heatermay be caused by a time lag in the current waveform (for example, thecurrent has a phase shift relative to the voltage due to an inductiveload) and/or by distortions in the current waveform (for example,distortions in the current waveform caused by introduced harmonics dueto a non-linear load). Thus, it may take more current to apply aselected amount of power due to phase shifting or waveform distortion.The ratio of actual power applied and the apparent power that would havebeen transmitted if the same current were in phase and undistorted isthe power factor. The power factor is always less than or equal to 1.The power factor is 1 when there is no phase shift or distortion in thewaveform.

Actual power applied to a heater due to a phase shift may be describedby EQN. 3:P=I×V×cos(θ);  (3)in which P is the actual power applied to a heater; 1 is the appliedcurrent; V is the applied voltage; and θ is the phase angle differencebetween voltage and current. Other phenomena such as waveform distortionmay contribute to further lowering of the power factor. If there is nodistortion in the waveform, then cos(θ) is equal to the power factor.

At higher frequencies (for example, modulated DC frequencies of at least1000 Hz, 1500 Hz, or 2000 Hz), the problem with phase shifting and/ordistortion is more pronounced. In certain embodiments, a capacitor isused to compensate for phase shifting caused by the inductive load.Capacitive load may be used to balance the inductive load becausecurrent for capacitance is 180 degrees out of phase from current forinductance. In some embodiments, a variable capacitor (for example, asolid state switching capacitor) is used to compensate for phaseshifting caused by a varying inductive load. In an embodiment, thevariable capacitor is placed at the wellhead for the temperature limitedheater. Placing the variable capacitor at the wellhead allows thecapacitance to be varied more easily in response to changes in theinductive load of the temperature limited heater. In certainembodiments, the variable capacitor is placed subsurface with thetemperature limited heater, subsurface within the heater, or as close tothe heating conductor as possible to minimize line losses due to thecapacitor. In some embodiments, the variable capacitor is placed at acentral location for a field of heater wells (in some embodiments, onevariable capacitor may be used for several temperature limited heaters).In one embodiment, the variable capacitor is placed at the electricaljunction between the field of heaters and the utility supply ofelectricity.

In certain embodiments, the variable capacitor is used to maintain thepower factor of the temperature limited heater or the power factor ofthe electrical conductors in the temperature limited heater above aselected value. In some embodiments, the variable capacitor is used tomaintain the power factor of the temperature limited heater above theselected value of 0.85, 0.9, or 0.95. In certain embodiments, thecapacitance in the variable capacitor is varied to maintain the powerfactor of the temperature limited heater above the selected value.

In some embodiments, the modulated DC waveform is pre-shaped tocompensate for phase shifting and/or harmonic distortion. The waveformmay be pre-shaped by modulating the waveform into a specific shape. Forexample, the DC modulator is programmed or designed to output a waveformof a particular shape. In certain embodiments, the pre-shaped waveformis varied to compensate for changes in the inductive load of thetemperature limited heater caused by changes in the phase shift and/orthe harmonic distortion. Electrical measurements may be used to assessthe phase shift and/or the harmonic distortion. In certain embodiments,heater conditions (for example, downhole temperature or pressure) areassessed and used to determine the pre-shaped waveform. In someembodiments, the pre-shaped waveform is determined through the use of asimulation or calculations based on the heater design. Simulationsand/or heater conditions may also be used to determine the capacitanceneeded for the variable capacitor.

In some embodiments, the modulated DC waveform modulates DC between 100%(full current load) and 0% (no current load). For example, a square-wavemay modulate 100 A DC between 100% (100 A) and 0% (0 A) (full wavemodulation), between 100% (100 A) and 50% (50 A), or between 75% (75 A)and 25% (25 A). The lower current load (for example, the 0%, 25%, or 50%current load) may be defined as the base current load.

Generally, a temperature limited heater designed for higher voltage andlower current will have a smaller skin depth. Decreasing the current maydecrease the skin depth of the ferromagnetic material. The smaller skindepth allows the temperature limited heater to have a smaller diameter,thereby reducing equipment costs. In certain embodiments, the appliedcurrent is at least 1 amp, 10 amps, 70 amps, 100 amps, 200 amps, 500amps, or greater up to 2000 amps. In some embodiments, current issupplied at voltages above 200 volts, above 480 volts, above 650 volts,above 1000 volts, above 1500 volts, or higher up to 10000 volts.

In certain embodiments, the temperature limited heater includes an innerconductor inside an outer conductor. The inner conductor and the outerconductor are radially disposed about a central axis. The inner andouter conductors may be separated by an insulation layer. In certainembodiments, the inner and outer conductors are coupled at the bottom ofthe temperature limited heater. Electrical current may flow into thetemperature limited heater through the inner conductor and returnthrough the outer conductor. One or both conductors may includeferromagnetic material.

The insulation layer may comprise an electrically insulating ceramicwith high thermal conductivity, such as magnesium oxide, aluminum oxide,silicon dioxide, beryllium oxide, boron nitride, silicon nitride, orcombinations thereof. The insulating layer may be a compacted powder(for example, compacted ceramic powder). Compaction may improve thermalconductivity and provide better insulation resistance. For lowertemperature applications, polymer insulation made from, for example,fluoropolymers, polyimides, polyamides, and/or polyethylenes, may beused. In some embodiments, the polymer insulation is made ofperfluoroalkoxy (PFA) or polyetheretherketone (PEEK™ (Victrex Ltd,England)). The insulating layer may be chosen to be substantiallyinfrared transparent to aid heat transfer from the inner conductor tothe outer conductor. In an embodiment, the insulating layer istransparent quartz sand. The insulation layer may be air or anon-reactive gas such as helium, nitrogen, or sulfur hexafluoride. Ifthe insulation layer is air or a non-reactive gas, there may beinsulating spacers designed to inhibit electrical contact between theinner conductor and the outer conductor. The insulating spacers may bemade of, for example, high purity aluminum oxide or another thermallyconducting, electrically insulating material such as silicon nitride.The insulating spacers may be a fibrous ceramic material such as Nextel™312 (3M Corporation, St. Paul, Minn., U.S.A.), mica tape, or glassfiber. Ceramic material may be made of alumina, alumina-silicate,alumina-borosilicate, silicon nitride, boron nitride, or othermaterials.

The insulation layer may be flexible and/or substantially deformationtolerant. For example, if the insulation layer is a solid or compactedmaterial that substantially fills the space between the inner and outerconductors, the temperature limited heater may be flexible and/orsubstantially deformation tolerant. Forces on the outer conductor can betransmitted through the insulation layer to the solid inner conductor,which may resist crushing. Such a temperature limited heater may bebent, dog-legged, and spiraled without causing the outer conductor andthe inner conductor to electrically short to each other. Deformationtolerance may be important if the wellbore is likely to undergosubstantial deformation during heating of the formation.

In certain embodiments, an outermost layer of the temperature limitedheater (for example, the outer conductor) is chosen for corrosionresistance, yield strength, and/or creep resistance. In one embodiment,austenitic (non-ferromagnetic) stainless steels such as 201, 304H, 347H,347HH, 316H, 310H, 347HP, NF709 (Nippon Steel Corp., Japan) stainlesssteels, or combinations thereof may be used in the outer conductor. Theoutermost layer may also include a clad conductor. For example, acorrosion resistant alloy such as 800H or 347H stainless steel may beclad for corrosion protection over a ferromagnetic carbon steel tubular.If high temperature strength is not required, the outermost layer may beconstructed from ferromagnetic metal with good corrosion resistance suchas one of the ferritic stainless steels. In one embodiment, a ferriticalloy of 82.3% by weight iron with 17.7% by weight chromium (Curietemperature of 678° C.) provides desired corrosion resistance.

The Metals Handbook, vol. 8, page 291 (American Society of Materials(ASM)) includes a graph of Curie temperature of iron-chromium alloysversus the amount of chromium in the alloys. In some temperature limitedheater embodiments, a separate support rod or tubular (made from 347Hstainless steel) is coupled to the temperature limited heater made froman iron-chromium alloy to provide yield strength and/or creepresistance. In certain embodiments, the support material and/or theferromagnetic material is selected to provide a 100,000 hourcreep-rupture strength of at least 20.7 MPa at 650° C. In someembodiments, the 100,000 hour creep-rupture strength is at least 13.8MPa at 650° C. or at least 6.9 MPa at 650° C. For example, 347H steelhas a favorable creep-rupture strength at or above 650° C. In someembodiments, the 100,000 hour creep-rupture strength ranges from 6.9 MPato 41.3 MPa or more for longer heaters and/or higher earth or fluidstresses.

In temperature limited heater embodiments with both an innerferromagnetic conductor and an outer ferromagnetic conductor, the skineffect current path occurs on the outside of the inner conductor and onthe inside of the outer conductor. Thus, the outside of the outerconductor may be clad with the corrosion resistant alloy, such asstainless steel, without affecting the skin effect current path on theinside of the outer conductor.

A ferromagnetic conductor with a thickness of at least the skin depth atthe Curie temperature allows a substantial decrease in resistance of theferromagnetic material as the skin depth increases sharply near theCurie temperature. In certain embodiments when the ferromagneticconductor is not clad with a highly conducting material such as copper,the thickness of the conductor may be 1.5 times the skin depth near theCurie temperature, 3 times the skin depth near the Curie temperature, oreven 10 or more times the skin depth near the Curie temperature. If theferromagnetic conductor is clad with copper, thickness of theferromagnetic conductor may be substantially the same as the skin depthnear the Curie temperature. In some embodiments, the ferromagneticconductor clad with copper has a thickness of at least three-fourths ofthe skin depth near the Curie temperature.

In certain embodiments, the temperature limited heater includes acomposite conductor with a ferromagnetic tubular and anon-ferromagnetic, high electrical conductivity core. Thenon-ferromagnetic, high electrical conductivity core reduces a requireddiameter of the conductor. For example, the conductor may be composite1.19 cm diameter conductor with a core of 0.575 cm diameter copper cladwith a 0.298 cm thickness of ferritic stainless steel or carbon steelsurrounding the core. The core or non-ferromagnetic conductor may becopper or copper alloy. The core or non-ferromagnetic conductor may alsobe made of other metals that exhibit low electrical resistivity andrelative magnetic permeabilities near 1 (for example, substantiallynon-ferromagnetic materials such as aluminum and aluminum alloys,phosphor bronze, beryllium copper, and/or brass). A composite conductorallows the electrical resistance of the temperature limited heater todecrease more steeply near the Curie temperature. As the skin depthincreases near the Curie temperature to include the copper core, theelectrical resistance decreases very sharply.

The composite conductor may increase the conductivity of the temperaturelimited heater and/or allow the heater to operate at lower voltages. Inan embodiment, the composite conductor exhibits a relatively flatresistance versus temperature profile at temperatures below a regionnear the Curie temperature of the ferromagnetic conductor of thecomposite conductor. In some embodiments, the temperature limited heaterexhibits a relatively flat resistance versus temperature profile between100° C. and 750° C. or between 300° C. and 600° C. The relatively flatresistance versus temperature profile may also be exhibited in othertemperature ranges by adjusting, for example, materials and/or theconfiguration of materials in the temperature limited heater. In certainembodiments, the relative thickness of each material in the compositeconductor is selected to produce a desired resistivity versustemperature profile for the temperature limited heater.

In certain embodiments, the relative thickness of each material in acomposite conductor is selected to produce a desired resistivity versustemperature profile for a temperature limited heater. In an embodiment,the composite conductor is an inner conductor surrounded by 0.127 cmthick magnesium oxide powder as an insulator. The outer conductor may be304H stainless steel with a wall thickness of 0.127 cm. The outsidediameter of the heater may be about 1.65 cm.

A composite conductor (for example, a composite inner conductor or acomposite outer conductor) may be manufactured by methods including, butnot limited to, coextrusion, roll forming, tight fit tubing (forexample, cooling the inner member and heating the outer member, theninserting the inner member in the outer member, followed by a drawingoperation and/or allowing the system to cool), explosive orelectromagnetic cladding, arc overlay welding, longitudinal stripwelding, plasma powder welding, billet coextrusion, electroplating,drawing, sputtering, plasma deposition, coextrusion casting, magneticforming, molten cylinder casting (of inner core material inside theouter or vice versa), insertion followed by welding or high temperaturebraising, shielded active gas welding (SAG), and/or insertion of aninner pipe in an outer pipe followed by mechanical expansion of theinner pipe by hydroforming or use of a pig to expand and swage the innerpipe against the outer pipe. In some embodiments, a ferromagneticconductor is braided over a non-ferromagnetic conductor. In certainembodiments, composite conductors are formed using methods similar tothose used for cladding (for example, cladding copper to steel). Ametallurgical bond between copper cladding and base ferromagneticmaterial may be advantageous. Composite conductors produced by acoextrusion process that forms a good metallurgical bond (for example, agood bond between copper and 446 stainless steel) may be provided byAnomet Products, Inc. (Shrewsbury, Mass., U.S.A.).

Several methods may also be used to form a composite conductor of morethan two conductors (for example, a three part composite conductor or afour part composite conductor). One method is to form two parts of thecomposite conductor by coextrusion and then swaging down the thirdand/or fourth parts of the composite conductor onto the coextrudedparts. A second method involves forming two or more parts of thecomposite conductor by coextrusion or another method, bending a strip ofthe outer conductor around the formed parts, and then welding the outerconductor together. The welding of the outer conductor may penetratedeep enough to create good electrical contact to the inner parts of thecomposite conductor. Another method is to swage all parts of thecomposite conductor onto one another either simultaneously or in two ormore steps. In another method, all parts of the composite conductor arecoextruded simultaneously. In another method, explosive cladding may beused to form a composite conductor. Explosive cladding may involveplacing a first material in a second material and submerging thecomposite material in a substantially non-compressible fluid. Anexplosive charge may be set off in the fluid to bind the first materialto the second material.

In an embodiment, two or more conductors are joined to form a compositeconductor by various methods (for example, longitudinal strip welding)to provide tight contact between the conducting layers. In certainembodiments, two or more conducting layers and/or insulating layers arecombined to form a composite heater with layers selected such that thecoefficient of thermal expansion decreases with each successive layerfrom the inner layer toward the outer layer. As the temperature of theheater increases, the innermost layer expands to the greatest degree.Each successive outwardly lying layer expands to a slightly lesserdegree, with the outermost layer expanding the least. This sequentialexpansion may provide relatively intimate contact between layers forgood electrical contact between layers.

In an embodiment, two or more conductors are drawn together to form acomposite conductor. In certain embodiments, a relatively malleableferromagnetic conductor (for example, iron such as 1018 steel) may beused to form a composite conductor. A relatively soft ferromagneticconductor typically has a low carbon content. A relatively malleableferromagnetic conductor may be useful in drawing processes for formingcomposite conductors and/or other processes that require stretching orbending of the ferromagnetic conductor. In a drawing process, theferromagnetic conductor may be annealed after one or more steps of thedrawing process. The ferromagnetic conductor may be annealed in an inertgas atmosphere to inhibit oxidation of the conductor. In someembodiments, oil is placed on the ferromagnetic conductor to inhibitoxidation of the conductor during processing.

The diameter of a temperature limited heater may be small enough toinhibit deformation of the heater by a collapsing formation. In certainembodiments, the outside diameter of a temperature limited heater isless than about 5 cm. In some embodiments, the outside diameter of atemperature limited heater is less than about 4 cm, less than about 3cm, or between about 2 cm and about 5 cm.

In heater embodiments described herein (including, but not limited to,temperature limited heaters, insulated conductor heaters,conductor-in-conduit heaters, and elongated member heaters), a largesttransverse cross-sectional dimension of a heater may be selected toprovide a desired ratio of the largest transverse cross-sectionaldimension to wellbore diameter (for example, initial wellbore diameter).The largest transverse cross-sectional dimension is the largestdimension of the heater on the same axis as the wellbore diameter (forexample, the diameter of a cylindrical heater or the width of a verticalheater). In certain embodiments, the ratio of the largest transversecross-sectional dimension to wellbore diameter is selected to be lessthan about 1:2, less than about 1:3, or less than about 1:4. The ratioof heater diameter to wellbore diameter may be chosen to inhibit contactand/or deformation of the heater by the formation during heating. Forexample, the ratio of heater diameter to wellbore diameter may be chosento inhibit closing in of the wellbore on the heater during heating. Incertain embodiments, the wellbore diameter is determined by a diameterof a drill bit used to form the wellbore.

A wellbore diameter may shrink from an initial value of about 16.5 cm toabout 6.4 cm during heating of a formation (for example, for a wellborein oil shale with a richness greater than about 0.12 L/kg). At somepoint, expansion of formation material into the wellbore during heatingresults in a balancing between the hoop stress of the wellbore and thecompressive strength due to thermal expansion of hydrocarbon, orkerogen, rich layers. The hoop stress of the wellbore itself may reducethe stress applied to a conduit (for example, a liner) located in thewellbore. At this point, the formation may no longer have the strengthto deform or collapse a heater or a liner. For example, the radialstress provided by formation material may be about 12,000 psi (82.7 MPa)at a diameter of about 16.5 cm, while the stress at a diameter of about6.4 cm after expansion may be about 3000 psi (20.7 MPa). A heaterdiameter may be selected to be less than about 3.8 cm to inhibit contactof the formation and the heater. A temperature limited heater mayadvantageously provide a higher heat output over a significant portionof the wellbore (for example, the heat output needed to providesufficient heat to pyrolyze hydrocarbons in a hydrocarbon containingformation) than a constant wattage heater for smaller heater diameters(for example, less than about 5.1 cm).

FIG. 40 depicts an embodiment of an apparatus used to form a compositeconductor. Ingot 608 may be a ferromagnetic conductor (for example, ironor carbon steel). Ingot 608 may be placed in chamber 610. Chamber 610may be made of materials that are electrically insulating and able towithstand temperatures of about 800° C. or higher. In one embodiment,chamber 610 is a quartz chamber. In some embodiments, an inert, ornon-reactive, gas (for example, argon or nitrogen with a smallpercentage of hydrogen) may be placed in chamber 610. In certainembodiments, a flow of inert gas is provided to chamber 610 to maintaina pressure in the chamber. Induction coil 612 may be placed aroundchamber 610. An alternating current may be supplied to induction coil612 to inductively heat ingot 608. Inert gas inside chamber 610 mayinhibit oxidation or corrosion of ingot 608.

Inner conductor 614 may be placed inside ingot 608. Inner conductor 614may be a non-ferromagnetic conductor (for example, copper or aluminum)that melts at a lower temperature than ingot 608. In an embodiment,ingot 608 may be heated to a temperature above the melting point ofinner conductor 614 and below the melting point of the ingot. Innerconductor 614 may melt and substantially fill the space inside ingot 608(for example, the inner annulus of the ingot). A cap may be placed atthe bottom of ingot 608 to inhibit inner conductor 614 from flowingand/or leaking out of the inner annulus of the ingot. After innerconductor 614 has sufficiently melted to substantially fill the innerannulus of ingot 608, the inner conductor and the ingot may be allowedto cool to room temperature. Ingot 608 and inner conductor 614 may becooled at a relatively slow rate to allow inner conductor 614 to form agood soldering bond with ingot 608. The rate of cooling may depend on,for example, the types of materials used for the ingot and the innerconductor.

In some embodiments, a composite conductor may be formed by tube-in-tubemilling of dual metal strips, such as the process performed by PrecisionTube Technology (Houston, Tex., U.S.A.). A tube-in-tube milling processmay also be used to form cladding on a conductor (for example, coppercladding inside carbon steel) or to form two materials into a tight fittube-within-a-tube configuration.

FIG. 41 depicts a cross-section representation of an embodiment of aninner conductor and an outer conductor formed by a tube-in-tube millingprocess. Outer conductor 616 may be coupled to inner conductor 618.Outer conductor 616 may be weldable material such as steel. Innerconductor 618 may have a higher electrical conductivity than outerconductor 616. In an embodiment, inner conductor 618 is copper oraluminum. Weld bead 620 may be formed on outer conductor 616.

In a tube-in-tube milling process, flat strips of material for the outerconductor may have a thickness substantially equal to the desired wallthickness of the outer conductor. The width of the strips may allowformation of a tube of a desired inner diameter. The flat strips may bewelded end-to-end to form an outer conductor of a desired length. Flatstrips of material for the inner conductor may be cut such that theinner conductor formed from the strips fit inside the outer conductor.The flat strips of inner conductor material may be welded togetherend-to-end to achieve a length substantially the same as the desiredlength of the outer conductor. The flat strips for the outer conductorand the flat strips for the inner conductor may be fed into separateaccumulators. Both accumulators may be coupled to a tube mill. The twoflat strips may be sandwiched together at the beginning of the tubemill.

The tube mill may form the flat strips into a tube-in-tube shape. Afterthe tube-in-tube shape has been formed, a non-contact high frequencyinduction welder may heat the ends of the strips of the outer conductorto a forging temperature of the outer conductor. The ends of the stripsthen may be brought together to forge weld the ends of the outerconductor into a weld bead. Excess weld bead material may be cut off. Insome embodiments, the tube-in-tube produced by the tube mill is furtherprocessed (for example, annealed and/or pressed) to achieve a desiredsize and/or shape. The result of the tube-in-tube process may be aninner conductor in an outer conductor, as shown in FIG. 41.

FIGS. 42-87 depict various embodiments of temperature limited heaters.One or more features of an embodiment of the temperature limited heaterdepicted in any of these figures may be combined with one or morefeatures of other embodiments of temperature limited heaters depicted inthese figures. In certain embodiments described herein, temperaturelimited heaters are dimensioned to operate at a frequency of 60 Hz AC.It is to be understood that dimensions of the temperature limited heatermay be adjusted from those described herein in order for the temperaturelimited heater to operate in a similar manner at other AC frequencies orwith modulated DC current.

FIG. 42 depicts a cross-sectional representation of an embodiment of thetemperature limited heater with an outer conductor having aferromagnetic section and a non-ferromagnetic section. FIGS. 43 and 44depict transverse cross-sectional views of the embodiment shown in FIG.42. In one embodiment, ferromagnetic section 622 is used to provide heatto hydrocarbon layers in the formation. Non-ferromagnetic section 624 isused in the overburden of the formation. Non-ferromagnetic section 624provides little or no heat to the overburden, thus inhibiting heatlosses in the overburden and improving heater efficiency. Ferromagneticsection 622 includes a ferromagnetic material such as 409 stainlesssteel or 410 stainless steel. Ferromagnetic section 622 has a thicknessof 0.3 cm. Non-ferromagnetic section 624 is copper with a thickness of0.3 cm. Inner conductor 626 is copper. Inner conductor 626 has adiameter of 0.9 cm. Electrical insulator 628 is silicon nitride, boronnitride, magnesium oxide powder, or another suitable insulator material.Electrical insulator 628 has a thickness of 0.1 cm to 0.3 cm.

FIG. 45 depicts a cross-sectional representation of an embodiment of atemperature limited heater with an outer conductor having aferromagnetic section and a non-ferromagnetic section placed inside asheath. FIGS. 46, 47, and 48 depict transverse cross-sectional views ofthe embodiment shown in FIG. 45. Ferromagnetic section 622 is 410stainless steel with a thickness of 0.6 cm. Non-ferromagnetic section624 is copper with a thickness of 0.6 cm. Inner conductor 626 is copperwith a diameter of 0.9 cm. Outer conductor 630 includes ferromagneticmaterial. Outer conductor 630 provides some heat in the overburdensection of the heater. Providing some heat in the overburden inhibitscondensation or refluxing of fluids in the overburden. Outer conductor630 is 409, 410, or 446 stainless steel with an outer diameter of 3.0 cmand a thickness of 0.6 cm. Electrical insulator 628 includes compactedmagnesium oxide powder with a thickness of 0.3 cm. In some embodiments,electrical insulator 628 includes silicon nitride, boron nitride, orhexagonal type boron nitride. Conductive section 632 may couple innerconductor 626 with ferromagnetic section 622 and/or outer conductor 630.

FIG. 49 depicts a cross-sectional representation of an embodiment of atemperature limited heater with a ferromagnetic outer conductor. Theheater is placed in a corrosion resistant jacket. A conductive layer isplaced between the outer conductor and the jacket. FIGS. 50 and 51depict transverse cross-sectional views of the embodiment shown in FIG.49. Outer conductor 630 is a ¾″ Schedule 80 446 stainless steel pipe. Inan embodiment, conductive layer 634 is placed between outer conductor630 and jacket 636. Conductive layer 634 is a copper layer. Outerconductor 630 is clad with conductive layer 634. In certain embodiments,conductive layer 634 includes one or more segments (for example,conductive layer 634 includes one or more copper tube segments). Jacket636 is a 1¼″ Schedule 80 347H stainless steel pipe or a 1½″ Schedule 160347H stainless steel pipe. In an embodiment, inner conductor 626 is 4/0MGT-1000 furnace cable with stranded nickel-coated copper wire withlayers of mica tape and glass fiber insulation. 4/0 MGT-1000 furnacecable is UL type 5107 (available from Allied Wire and Cable(Phoenixville, Pa., U.S.A.)). Conductive section 632 couples innerconductor 626 and jacket 636. In an embodiment, conductive section 632is copper.

FIG. 52 depicts a cross-sectional representation of an embodiment of atemperature limited heater with an outer conductor. The outer conductorincludes a ferromagnetic section and a non-ferromagnetic section. Theheater is placed in a corrosion resistant jacket. A conductive layer isplaced between the outer conductor and the jacket. FIGS. 53 and 54depict transverse cross-sectional views of the embodiment shown in FIG.52. Ferromagnetic section 622 is 409, 410, or 446 stainless steel with athickness of 0.9 cm. Non-ferromagnetic section 624 is copper with athickness of 0.9 cm. Ferromagnetic section 622 and non-ferromagneticsection 624 are placed in jacket 636. Jacket 636 is 304 or 347Hstainless steel with a thickness of 0.1 cm. Conductive layer 634 is acopper layer. Electrical insulator 628 includes compacted siliconnitride, boron nitride, or magnesium oxide powder with a thickness of0.1 to 0.3 cm. Inner conductor 626 is copper with a diameter of 1.0 cm.

In an embodiment, ferromagnetic section 622 is 446 stainless steel witha thickness of 0.9 cm. Jacket 636 is 410 stainless steel with athickness of 0.6 cm. 410 stainless steel has a higher Curie temperaturethan 446 stainless steel. Such a temperature limited heater may“contain” current such that the current does not easily flow from theheater to the surrounding formation and/or to any surrounding water (forexample, brine, groundwater, or formation water). In this embodiment, amajority of the current flows through ferromagnetic section 622 untilthe Curie temperature of the ferromagnetic section is reached. After theCurie temperature of ferromagnetic section 622 is reached, a majority ofthe current flows through conductive layer 634. The ferromagneticproperties of jacket 636 (410 stainless steel) inhibit the current fromflowing outside the jacket and “contain” the current. Jacket 636 mayalso have a thickness that provides strength to the temperature limitedheater.

FIG. 55 depicts a cross-sectional representation of an embodiment of atemperature limited heater. The heating section of the temperaturelimited heater includes non-ferromagnetic inner conductors and aferromagnetic outer conductor. The overburden section of the temperaturelimited heater includes a non-ferromagnetic outer conductor. FIGS. 56,57, and 58 depict transverse cross-sectional views of the embodimentshown in FIG. 55. Inner conductor 626 is copper with a diameter of 1.0cm. Electrical insulator 628 is placed between inner conductor 626 andconductive layer 634. Electrical insulator 628 includes compactedsilicon nitride, boron nitride, or magnesium oxide powder with athickness of 0.1 cm to 0.3 cm. Conductive layer 634 is copper with athickness of 0.1 cm. Insulation layer 638 is in the annulus outside ofconductive layer 634. The thickness of the annulus may be 0.3 cm.Insulation layer 638 is quartz sand.

Heating section 640 may provide heat to one or more hydrocarbon layersin the formation. Heating section 640 includes ferromagnetic materialsuch as 409 stainless steel or 410 stainless steel. Heating section 640has a thickness of 0.9 cm. Endcap 642 is coupled to an end of heatingsection 640. Endcap 642 electrically couples heating section 640 toinner conductor 626 and/or conductive layer 634. Endcap 642 is 304stainless steel. Heating section 640 is coupled to overburden section644. Overburden section 644 includes carbon steel and/or other suitablesupport materials. Overburden section 644 has a thickness of 0.6 cm.Overburden section 644 is lined with conductive layer 646. Conductivelayer 646 is copper with a thickness of 0.3 cm.

FIG. 59 depicts a cross-sectional representation of an embodiment of atemperature limited heater with an overburden section and a heatingsection. FIGS. 60 and 61 depict transverse cross-sectional views of theembodiment shown in FIG. 59. The overburden section includes portion626A of inner conductor 626. Portion 626A is copper with a diameter of1.3 cm. The heating section includes portion 626B of inner conductor626. Portion 626B is copper with a diameter of 0.5 cm. Portion 626B isplaced in ferromagnetic conductor 654. Ferromagnetic conductor 654 is446 stainless steel with a thickness of 0.4 cm. Electrical insulator 628includes compacted silicon nitride, boron nitride, or magnesium oxidepowder with a thickness of 0.2 cm. Outer conductor 630 is copper with athickness of 0.1 cm. Outer conductor 630 is placed in jacket 636. Jacket636 is 316H or 347H stainless steel with a thickness of 0.2 cm.

FIG. 62A and FIG. 62B depict cross-sectional representations of anembodiment of a temperature limited heater with a ferromagnetic innerconductor. Inner conductor 626 is a 1″ Schedule XXS 446 stainless steelpipe. In some embodiments, inner conductor 626 includes 409 stainlesssteel, 410 stainless steel, Invar 36, alloy 42-6, alloy 52, or otherferromagnetic materials. Inner conductor 626 has a diameter of 2.5 cm.Electrical insulator 628 includes compacted silicon nitride, boronnitride, or magnesium oxide powders; or polymers, Nextel ceramic fiber,mica, or glass fibers. Outer conductor 630 is copper or any othernon-ferromagnetic material such as aluminum. Outer conductor 630 iscoupled to jacket 636. Jacket 636 is 304H, 316H, or 347H stainlesssteel. In this embodiment, a majority of the heat is produced in innerconductor 626.

FIG. 63A and FIG. 63B depict cross-sectional representations of anembodiment of a temperature limited heater with a ferromagnetic innerconductor and a non-ferromagnetic core. Inner conductor 626 may be madeof 446 stainless steel, 409 stainless steel, 410 stainless steel, carbonsteel, Armco ingot iron, iron-cobalt alloys, or other ferromagneticmaterials. Core 656 may be tightly bonded inside inner conductor 626.Core 656 is copper or other non-ferromagnetic material. In certainembodiments, core 656 is inserted as a tight fit inside inner conductor626 before a drawing operation. In some embodiments, core 656 and innerconductor 626 are coextrusion bonded. Outer conductor 630 is 347Hstainless steel. A drawing or rolling operation to compact electricalinsulator 628 (for example, compacted silicon nitride, boron nitride, ormagnesium oxide powder) may ensure good electrical contact between innerconductor 626 and core 656. In this embodiment, heat is producedprimarily in inner conductor 626 until the Curie temperature isapproached. Resistance then decreases sharply as current penetrates core656.

FIG. 64A and FIG. 64B depict cross-sectional representations of anembodiment of a temperature limited heater with a ferromagnetic outerconductor. Inner conductor 626 is nickel-clad copper. Electricalinsulator 628 is silicon nitride, boron nitride, or magnesium oxide.Outer conductor 630 is a 1″ Schedule XXS carbon steel pipe. In thisembodiment, heat is produced primarily in outer conductor 630, resultingin a small temperature differential across electrical insulator 628.

FIG. 65A and FIG. 65B depict cross-sectional representations of anembodiment of a temperature limited heater with a ferromagnetic outerconductor that is clad with a corrosion resistant alloy. Inner conductor626 is copper. Outer conductor 630 is a 1″ Schedule XXS carbon steelpipe. Outer conductor 630 is coupled to jacket 636. Jacket 636 is madeof corrosion resistant material (for example, 347H stainless steel).Jacket 636 provides protection from corrosive fluids in the wellbore(for example, sulfidizing and carburizing gases). Heat is producedprimarily in outer conductor 630, resulting in a small temperaturedifferential across electrical insulator 628.

FIG. 66A and FIG. 66B depict cross-sectional representations of anembodiment of a temperature limited heater with a ferromagnetic outerconductor. The outer conductor is clad with a conductive layer and acorrosion resistant alloy. Inner conductor 626 is copper. Electricalinsulator 628 is silicon nitride, boron nitride, or magnesium oxide.Outer conductor 630 is a 1″ Schedule 80446 stainless steel pipe. Outerconductor 630 is coupled to jacket 636. Jacket 636 is made fromcorrosion resistant material such as 347H stainless steel. In anembodiment, conductive layer 634 is placed between outer conductor 630and jacket 636. Conductive layer 634 is a copper layer. Heat is producedprimarily in outer conductor 630, resulting in a small temperaturedifferential across electrical insulator 628. Conductive layer 634allows a sharp decrease in the resistance of outer conductor 630 as theouter conductor approaches the Curie temperature. Jacket 636 providesprotection from corrosive fluids in the wellbore.

In an embodiment, a temperature limited heater includes triaxialconductors. FIG. 67A and FIG. 67B depict cross-sectional representationsof an embodiment of a temperature limited heater with triaxialconductors. Inner conductor 626 may be copper or another highlyconductive material. Electrical insulator 628 may be silicon nitride,boron nitride, or magnesium oxide (in certain embodiments, as compactedpowders). Middle conductor 658 may include ferromagnetic material (forexample, 446 stainless steel). In the embodiment of FIGS. 67A and 67B,outer conductor 630 is separated from middle conductor 658 by electricalinsulator 628. Outer conductor 630 may include corrosion resistant,electrically conductive material (for example, stainless steel). In someembodiments, electrical insulator 628 is a space between conductors (forexample, an air gap or other gas gap) that electrically insulates theconductors (for example, conductors 626, 630, and 658 may be in aconductor-in-conduit-in-conduit arrangement).

In a temperature limited heater with triaxial conductors, such asdepicted in FIGS. 67A and 67B, electrical current may propagate throughtwo conductors in one direction and through the third conductor in anopposite direction. In FIGS. 67A and 67B, electrical current maypropagate in through middle conductor 658 in one direction and returnthrough inner conductor 626 and outer conductor 630 in an oppositedirection, as shown by the arrows in FIG. 67A and the +/− signs in FIG.67B. In an embodiment, electrical current is split approximately in halfbetween inner conductor 626 and outer conductor 630. Splitting theelectrical current between inner conductor 626 and outer conductor 630causes current propagating through middle conductor 658 to flow throughboth inside and outside skin depths of the middle conductor.

Current flows through both the inside and outside skin depths due toreduced magnetic field intensity from the current being split betweenthe outer conductor and the inner conductor. Reducing the magnetic fieldintensity allows the skin depth of middle conductor 658 to remainrelatively small with the same magnetic permeability. Thus, the thinnerinside and outside skin depths may produce an increased Curie effectcompared to the same thickness of ferromagnetic material with only oneskin depth. The thinner inside and outside skin depths may produce asharper turndown than one single skin depth in the same ferromagneticmaterial. Splitting the current between outer conductor 630 and innerconductor 626 may allow a thinner middle conductor 658 to produce thesame Curie effect as a thicker middle conductor. In certain embodiments,the materials and thicknesses used for outer conductor 630, innerconductor 626 and middle conductor 658 have to be balanced to producedesired results in the Curie effect and turndown ratio of a triaxialtemperature limited heater.

In some embodiments, the conductor (for example, an inner conductor, anouter conductor, or a ferromagnetic conductor) is the compositeconductor that includes two or more different materials. In certainembodiments, the composite conductor includes two or more ferromagneticmaterials. In some embodiments, the composite ferromagnetic conductorincludes two or more radially disposed materials. In certainembodiments, the composite conductor includes a ferromagnetic conductorand a non-ferromagnetic conductor. In some embodiments, the compositeconductor includes the ferromagnetic conductor placed over anon-ferromagnetic core. Two or more materials may be used to obtain arelatively flat electrical resistivity versus temperature profile in atemperature region below the Curie temperature and/or a sharp decrease(a high turndown ratio) in the electrical resistivity at or near theCurie temperature. In some cases, two or more materials are used toprovide more than one Curie temperature for the temperature limitedheater.

In certain embodiments, a composite electrical conductor is formed usinga billet coextrusion process. A billet coextrusion process may includecoupling together two or more electrical conductors at relatively hightemperatures (for example, at temperatures that are near or above 75% ofthe melting temperature of a conductor). The electrical conductors maybe drawn together at the relatively high temperatures (for example,under vacuum). Coextrusion at high temperatures under vacuum exposesfresh metal surfaces during drawing while inhibiting oxidation of themetal surfaces. This type of coextrusion improves the metallurgical bondbetween coextruded metals. The drawn together conductors may then becooled to form a composite electrical conductor made from the two ormore electrical conductors. In some embodiments, the compositeelectrical conductor is a solid composite electrical conductor. Incertain embodiments, the composite electrical conductor may be a tubularcomposite electrical conductor.

In one embodiment, a copper core is billet coextruded with a stainlesssteel conductor (for example, 446 stainless steel). The copper core andthe stainless steel conductor may be heated to a softening temperaturein vacuum. At the softening temperature, the stainless steel conductormay be drawn over the copper core to form a tight fit. The stainlesssteel conductor and copper core may then be cooled to form a compositeelectrical conductor with the stainless steel surrounding the coppercore.

In some embodiments, a long, composite electrical conductor is formedfrom several sections of composite electrical conductor. The sections ofcomposite electrical conductor may be formed by a billet coextrusionprocess. The sections of composite electrical conductor may be coupledusing a welding process. FIGS. 68, 69, and 70 depict embodiments ofcoupled sections of composite electrical conductors. In FIG. 68, core656 extends beyond the ends of inner conductor 626 in each section of acomposite electrical conductor. In an embodiment, core 656 is copper andinner conductor 626 is 446 stainless steel. Cores 656 from each sectionof the composite electrical conductor may be coupled by, for example,brazing the core ends together. Core coupling material 650 may couplethe core ends, as shown in FIG. 68. Core coupling material 650 may be,for example Everdur, a copper-silicon alloy material (for example, analloy with about 3% by weight silicon in copper). Alternatively, thecopper core may be autogenously welded or filled with copper.

Inner conductor coupling material 652 may couple inner conductors 626from each section of the composite electrical conductor. Inner conductorcoupling material 652 may be material used for welding sections of innerconductor 626 together. In certain embodiments, inner conductor couplingmaterial 652 may be used for welding stainless steel inner conductorsections together. In some embodiments, inner conductor couplingmaterial 652 is 304 stainless steel or 310 stainless steel. A thirdmaterial (for example, 309 stainless steel) may be used to couple innerconductor coupling material 652 to ends of inner conductor 626. Thethird material may be needed or desired to produce a better bond (forexample, a better weld) between inner conductor 626 and inner conductorcoupling material 652. The third material may be non-magnetic to reducethe potential for a hot spot to occur at the coupling.

In certain embodiments, inner conductor coupling material 652 surroundsthe ends of cores 656 that protrude beyond the ends of inner conductors626, as shown in FIG. 68. Inner conductor coupling material 652 mayinclude one or more coupled portions. Inner conductor coupling material652 may be placed in a clam shell configuration around the ends of cores656 that protrude beyond the ends of inner conductors 626, as shown inthe end view depicted in FIG. 69. Coupling material 660 may be used tocouple together portions (for example, halves) of inner conductorcoupling material 652. Coupling material 660 may be the same material asinner conductor coupling material 652 or another material suitable forcoupling together portions of the inner conductor coupling material.

In some embodiments, a composite electrical conductor includes innerconductor coupling material 652 with 304 stainless steel or 310stainless steel and inner conductor 626 with 446 stainless steel oranother ferromagnetic material. In such an embodiment, inner conductorcoupling material 652 produces significantly less heat than innerconductor 626. The portions of the composite electrical conductor thatinclude the inner conductor coupling material (for example, the weldedportions or “joints” of the composite electrical conductor) may remainat lower temperatures than adjacent material during application ofapplied electrical current to the composite electrical conductor. Thereliability and durability of the composite electrical conductor may beincreased by keeping the joints of the composite electrical conductor atlower temperatures.

FIG. 70 depicts an embodiment for coupling together sections of acomposite electrical conductor. Ends of cores 656 and ends of innerconductors 626 are beveled to facilitate coupling the sections of thecomposite electrical conductor. Core coupling material 650 may couple(for example, braze) the ends of each core 656. The ends of each innerconductor 626 may be coupled (for example, welded) together with innerconductor coupling material 652. Inner conductor coupling material 652may be 309 stainless steel or another suitable welding material. In someembodiments, inner conductor coupling material 652 is 309 stainlesssteel. 309 stainless steel may reliably weld to both an inner conductorhaving 446 stainless steel and a core having copper. Using beveled endswhen coupling together sections of a composite electrical conductor mayproduce a reliable and durable coupling between the sections ofcomposite electrical conductor. FIG. 70 depicts a weld formed betweenends of sections that have beveled surfaces.

The composite electrical conductor may be used as the conductor in anyelectrical heater embodiment described herein. For example, thecomposite conductor may be used as the conductor in aconductor-in-conduit heater or an insulated conductor heater. In certainembodiments, the composite conductor may be coupled to a support membersuch as a support conductor. The support member may be used to providesupport to the composite conductor so that the composite conductor isnot relied upon for strength at or near the Curie temperature. Thesupport member may be useful for heaters of lengths of at least 100 m.The support member may be a non-ferromagnetic member that has good hightemperature creep strength. Examples of materials that are used for asupport member include, but are not limited to, Haynes® 625 alloy andHaynes® HR120® alloy (Haynes International, Kokomo, Ind., U.S.A.),NF709, Incoloy® 800H alloy and 347HP alloy (Allegheny Ludlum Corp.,Pittsburgh, Pa., U.S.A.). In some embodiments, materials in a compositeconductor are directly coupled (for example, brazed, metallurgicallybonded, or swaged) to each other and/or the support member. Using asupport member may reduce the need for the ferromagnetic member toprovide support for the temperature limited heater, especially at ornear the Curie temperature. Thus, the temperature limited heater may bedesigned with more flexibility in the selection of ferromagneticmaterials.

FIG. 71 depicts a cross-sectional representation of an embodiment of thecomposite conductor with the support member. Core 656 is surrounded byferromagnetic conductor 654 and support member 662. In some embodiments,core 656, ferromagnetic conductor 654, and support member 662 aredirectly coupled (for example, brazed together or metallurgically bondedtogether). In one embodiment, core 656 is copper, ferromagneticconductor 654 is 446 stainless steel, and support member 662 is 347Halloy. In certain embodiments, support member 662 is a Schedule 80 pipe.Support member 662 surrounds the composite conductor havingferromagnetic conductor 654 and core 656. Ferromagnetic conductor 654and core 656 may be joined to form the composite conductor by, forexample, a coextrusion process. For example, the composite conductor isa 1.9 cm outside diameter 446 stainless steel ferromagnetic conductorsurrounding a 0.95 cm diameter copper core.

In certain embodiments, the diameter of core 656 is adjusted relative toa constant outside diameter of ferromagnetic conductor 654 to adjust theturndown ratio of the temperature limited heater. For example, thediameter of core 656 may be increased to 1.14 cm while maintaining theoutside diameter of ferromagnetic conductor 654 at 1.9 cm to increasethe turndown ratio of the heater.

In some embodiments, conductors (for example, core 656 and ferromagneticconductor 654) in the composite conductor are separated by supportmember 662. FIG. 72 depicts a cross-sectional representation of anembodiment of the composite conductor with support member 662 separatingthe conductors. In one embodiment, core 656 is copper with a diameter of0.95 cm, support member 662 is 347H alloy with an outside diameter of1.9 cm, and ferromagnetic conductor 654 is 446 stainless steel with anoutside diameter of 2.7 cm. The support member depicted in FIG. 72 has alower creep strength relative to the support members depicted in FIG.71.

In certain embodiments, support member 662 is located inside thecomposite conductor. FIG. 73 depicts a cross-sectional representation ofan embodiment of the composite conductor surrounding support member 662.Support member 662 is made of 347H alloy. Inner conductor 626 is copper.Ferromagnetic conductor 654 is 446 stainless steel. In one embodiment,support member 662 is, 1.25 cm diameter 347H alloy, inner conductor 626is 1.9 cm outside diameter copper, and ferromagnetic conductor 654 is2.7 cm outside diameter 446 stainless steel. The turndown ratio ishigher than the turndown ratio for the embodiments depicted in FIGS. 71,72, and 74 for the same outside diameter, but it has a lower creepstrength.

In some embodiments, the thickness of inner conductor 626, which iscopper, is reduced and the thickness of support member 662 is increasedto increase the creep strength at the expense of reduced turndown ratio.For example, the diameter of support member 662 is increased to 1.6 cmwhile maintaining the outside diameter of inner conductor 626 at 1.9 cmto reduce the thickness of the conduit. This reduction in thickness ofinner conductor 626 results in a decreased turndown ratio relative tothe thicker inner conductor embodiment but an increased creep strength.

In one embodiment, support member 662 is a conduit (or pipe) insideinner conductor 626 and ferromagnetic conductor 654. FIG. 74 depicts across-sectional representation of an embodiment of the compositeconductor surrounding support member 662. In one embodiment, supportmember 662 is 347H alloy with a 0.63 cm diameter center hole. In someembodiments, support member 662 is a preformed conduit. In certainembodiments, support member 662 is formed by having a dissolvablematerial (for example, copper dissolvable by nitric acid) located insidethe support member during formation of the composite conductor. Thedissolvable material is dissolved to form the hole after the conductoris assembled. In an embodiment, support member 662 is 347H alloy with aninside diameter of 0.63 cm and an outside diameter of 1.6 cm, innerconductor 626 is copper with an outside diameter of 1.8 cm, andferromagnetic conductor 654 is 446 stainless steel with an outsidediameter of 2.7 cm.

In certain embodiments, the composite electrical conductor is used asthe conductor in the conductor-in-conduit heater. For example, thecomposite electrical conductor may be used as conductor 666 in FIG. 75

FIG. 75 depicts a cross-sectional representation of an embodiment of theconductor-in-conduit heater. Conductor 666 is disposed in conduit 668.Conductor 666 is a rod or conduit of electrically conductive material.Low resistance sections 670 are present at both ends of conductor 666 togenerate less heating in these sections. Low resistance section 670 isformed by having a greater cross-sectional area of conductor 666 in thatsection, or the sections are made of material having less resistance. Incertain embodiments, low resistance section 670 includes a lowresistance conductor coupled to conductor 666.

Conduit 668 is made of an electrically conductive material. Conduit 668is disposed in opening 378 in hydrocarbon layer 380. Opening 378 has adiameter that accommodates conduit 668.

Conductor 666 may be centered in conduit 668 by centralizers 672.Centralizers 672 electrically isolate conductor 666 from conduit 668.Centralizers 672 inhibit movement and properly locate conductor 666 inconduit 668. Centralizers 672 are made of ceramic material or acombination of ceramic and metallic materials. Centralizers 672 inhibitdeformation of conductor 666 in conduit 668. Centralizers 672 aretouching or spaced at intervals between approximately 0.1 m (meters) andapproximately 3 m or more along conductor 666.

A second low resistance section 670 of conductor 666 may coupleconductor 666 to wellhead 418, as depicted in FIG. 75. Electricalcurrent may be applied to conductor 666 from power cable 676 through lowresistance section 670 of conductor 666. Electrical current passes fromconductor 666 through sliding connector 678 to conduit 668. Conduit 668may be electrically insulated from overburden casing 680 and fromwellhead 418 to return electrical current to power cable 676. Heat maybe generated in conductor 666 and conduit 668. The generated heat mayradiate in conduit 668 and opening 378 to heat at least a portion ofhydrocarbon layer 380.

Overburden casing 680 may be disposed in overburden 382. Overburdencasing 680 is, in some embodiments, surrounded by materials (forexample, reinforcing material and/or cement) that inhibit heating ofoverburden 382. Low resistance section 670 of conductor 666 may beplaced in overburden casing 680. Low resistance section 670 of conductor666 is made of, for example, carbon steel. Low resistance section 670 ofconductor 666 may be centralized in overburden casing 680 usingcentralizers 672. Centralizers 672 are spaced at intervals ofapproximately 6 m to approximately 12 m or, for example, approximately 9m along low resistance section 670 of conductor 666. In a heaterembodiment, low resistance section 670 of conductor 666 is coupled toconductor 666 by one or more welds. In other heater embodiments, lowresistance sections are threaded, threaded and welded, or otherwisecoupled to the conductor. Low resistance section 670 generates little orno heat in overburden casing 680. Packing 520 may be placed betweenoverburden casing 680 and opening 378. Packing 520 may be used as a capat the junction of overburden 382 and hydrocarbon layer 380 to allowfilling of materials in the annulus between overburden casing 680 andopening 378. In some embodiments, packing 520 inhibits fluid fromflowing from opening 378 to surface 550.

FIG. 76 depicts a cross-sectional representation of an embodiment of aremovable conductor-in-conduit heat source. Conduit 668 may be placed inopening 378 through overburden 382 such that a gap remains between theconduit and overburden casing 680. Fluids may be removed from opening378 through the gap between conduit 668 and overburden casing 680.Fluids may be removed from the gap through conduit 682. Conduit 668 andcomponents of the heat source included in the conduit that are coupledto wellhead 418 may be removed from opening 378 as a single unit. Theheat source may be removed as a single unit to be repaired, replaced,and/or used in another portion of the formation.

Water or other fluids inside conduit 668 can adversely affect heatingusing the conductor-in-conduit heater. In certain embodiments, fluidinside conduit 668 is removed to reduce the pressure inside the conduit.The fluid may be removed by vacuum pumping or other means for reducingthe pressure inside conduit 668. In some embodiments, the pressure isreduced outside conduit 668 and inside opening 378. In certainembodiments, the space inside conduit 668 or the space outside theconduit is vacuum pumped to a pressure below the vapor pressure of waterat the downhole temperature of the conduit. For example, at a downholetemperature of 25° C., the space inside or outside conduit 668 would bevacuum pumped to a pressure below about 101 kPa.

In certain embodiments, the space inside or outside conduit 668 isvacuum pumped to a pressure below the vapor pressure of water at icetemperatures. The vapor pressure of ice at 0° C. is 610 Pa. As conduit668 is vacuum pumped, water in the conduit gets colder until the waterfreezes. Thus, vacuum pumping to a pressure below the vapor pressure ofwater at ice temperatures indicates that most or all of the water hasbeen removed from the space inside or outside conduit 668. In certainembodiments, high pumping capacity vacuum pumps (for example, a Kinney®CB245 vacuum pump available from Tuthill Co. (Burr Ridge, Ill., U.S.A.))are used to vacuum pump below pressures of about 1 Pa. In someembodiments, a vacuum gauge is coupled between the vacuum pump and thewellhead for the heater. In some embodiments, a cold trap (for example,a dry ice trap or liquid nitrogen trap) is placed between conduit 668and the vacuum pump to condense water from the conduit and inhibit waterfrom contaminating pump oil.

As pressure in conduit 668 is decreased, ice in the conduit gets colder,and the vapor pressure of the ice further decreases. For example, thevapor pressure of ice at (−10)° C. is 260 Pa. Thus, in certainembodiments, the space inside or outside conduit 668 is vacuum pumped toa pressure below 1 kPa, below 750 Pa, below 600 Pa, below 500 Pa, below100 Pa, 15 Pa, below 10 Pa, below 5 Pa, or less. Vacuum pumping to suchpressures improves the removal of water from conduit 668.

In some embodiments, conduit 668 is vacuum pumped to a selected pressureand then the conduit is closed off (pressure sealed), for example, byclosing a valve on the wellhead. The pressure in conduit 668 ismonitored for any pressure rise. If the pressure rises to a value nearthe vapor pressure of water or ice and at least temporarily stabilizes,there is most likely more water in the conduit and the conduit is thenvacuum pumped again. If the pressure does not rise up to the vaporpressure of ice or water, then conduit 668 is considered dry. If thepressure continuously rises to pressures above the vapor pressure of iceor water, then there may be a leak in conduit 668 causing the pressurerise.

In certain embodiments, heat is provided by conductor 666 and/or conduit668 during vacuum pumping of the conduit. The provided heat may increasethe vapor pressure of water or ice in conduit 668. The provided heat mayinhibit ice from forming in conduit 668. Providing heat in conduit 668may decrease the time needed to remove (vacuum pump) water from theconduit. Providing heat in conduit 668 may increase the likelihood ofremoving substantially all the water from the conduit.

In some embodiments, a non-condensable gas (for example, dry nitrogen,argon, or helium) is backfilled inside or outside conduit 668 aftervacuum pumping. In some embodiments, the space inside or outside conduit668 is backfilled with the non-condensable gas to a pressure between 101kPa and 10 MPa, between 202 kPa and 5 MPa, or between 500 kPa and 1 MPa.In some embodiments, the inside or outside of conduit 668 is vacuumpumped for a time, then backfilled with non-condensable gas, and thenvacuum pumped again. This process may be repeated for several cycles tomore completely remove water and other fluids from inside or outsideconduit 668. In some embodiments, conduit 668 is operated with thebackfilled non-condensable gas remaining inside or outside the conduit.

In some embodiments, a small amount of an oxidizing fluid, such asoxygen, is added to the non-condensable gas backfilled in conduit 668.The oxidizing fluid may oxidize metals of conduit 668 and/or conductor666. The oxidation may increase the emissivity of the conduit and/orconductor metals. The small amount of oxidizing fluid may be betweenabout 100 ppm and 25 ppm, between about 75 ppm and 40 ppm, or betweenabout 60 ppm and 50 ppm in the non-condensable gas. In one embodiment,at most 50 ppm of oxidizing fluid is in the non-condensable gas inconduit 668.

FIG. 77 depicts an embodiment of a sliding connector. Sliding connector678 may be coupled near an end of conductor 666. Sliding connector 678may be positioned near a bottom end of conduit 668. Sliding connector678 may electrically couple conductor 666 to conduit 668. Slidingconnector 678 may move during use to accommodate thermal expansionand/or contraction of conductor 666 and conduit 668 relative to eachother. In some embodiments, sliding connector 678 may be attached to lowresistance section 670 of conductor 666. The lower resistance of lowresistance section 670 may allow the sliding connector to be at atemperature that does not exceed about 90° C. Maintaining slidingconnector 678 at a relatively low temperature may inhibit corrosion ofthe sliding connector and promote good contact between the slidingconnector and conduit 668.

Sliding connector 678 may include scraper 684. Scraper 684 may abut aninner surface of conduit 668 at point 686. Scraper 684 may include anymetal or electrically conducting material (for example, steel orstainless steel). Centralizer 688 may couple to conductor 666. In someembodiments, sliding connector 678 is positioned on low resistancesection 670 of conductor 666. Centralizer 688 may include anyelectrically conducting material (for example, a metal or metal alloy).Spring bow 690 may couple scraper 684 to centralizer 688. Spring bow 690may include any metal or electrically conducting material (for example,copper-beryllium alloy). In some embodiments, centralizer 688, springbow 690, and/or scraper 684 are welded together.

More than one sliding connector 678 may be used for redundancy and toreduce the current through each scraper 684. In addition, a thickness ofconduit 668 may be increased for a length adjacent to sliding connector678 to reduce heat generated in that portion of conduit. The length ofconduit 668 with increased thickness may be, for example, approximately6 m. In certain embodiments, electrical contact may be made betweencentralizer 688 and scraper 684 (shown in FIG. 77) on sliding connector678 using an electrical conductor (for example, a copper wire) that hasa lower electrical resistance than spring bow 690. Electrical currentmay flow through the electrical conductor rather than spring bow 690 sothat the spring bow has a longer lifetime.

FIG. 78A depicts an embodiment of contacting sections for aconductor-in-conduit heater. Conductor 666 and conduit 668 form theconductor-in-conduit heater. In the upper contact section, lead-in cable692 provides power to conductor 666 and conduit 668. Connector 694couples lead-in cable 692 to conductor 666. Conductor 666 is supportedby rod 696. In certain embodiments, rod 696 is a sucker rod such as afiberglass, stainless steel, or carbon steel sucker rod. A fiberglasssucker rod may have lower proximity effect losses than a sucker rod madeof stainless steel or carbon steel. Rod 696 and conductor 666 areelectrically isolated by isolation sub 698.

Return electrical current enters the upper contacting section throughconduit 668. Conduit 668 is electrically coupled to return cable 700through contactor 702. In certain embodiments, liner 704 is located onthe inside of conduit 668 to promote electrical contact between theconduit and contactor 702. In certain embodiments, liner 704 is copper.In some embodiments, conduit 668 includes one or more isolation subs698. Isolation subs 698 in conduit 668 inhibit any current flow tosections above the contacting section of the conduit. Isolation subs 698may be, for example fiberglass sections of conduit 668 or electricallyinsulating epoxy threaded sections in the conduit.

Lead-in cable 692 and return cable 700 may be 4-0 copper cable withTEFLON® insulation. Using copper cables to make electrical contact inthe upper contacting section may be less expensive than other contactingmethods such as cladding. In certain embodiments, more than one cable isused for lead-in cable 692 and/or return cable 700. FIG. 78B depicts anaerial view of the upper contact section of the conductor-in-conduitheater in FIG. 78A with three lead-in cables 692 and three return cables700. The cables are coupled to rod 696 with strap 706. Centralizers 672maintain a position of rod 696 in conduit 668. The lead-in cables andreturn cables may be paired off in three pairs. Each pair may have onelead-in cable 692 and one return cable 700. Thus, in each cable pair,one cable carries current downwards (lead-in cables) and one cablecarries current upwards (return cables). This opposite current flow ineach pair reduces skin effect losses in the upper contacting section. Inaddition, splitting the lead-in and return current between severalcables reduces electrical loss and heat loss in the upper contactingsection.

In the lower contacting section shown in FIG. 78A, conductor 666 iselectrically coupled to conduit 668 through contactors 702. In certainembodiments, liner 704 is located on the inside of conduit 668 topromote electrical contact between the conduit and contactors 702.

In some embodiments, a fiber optic system including an optical sensor isused to continuously monitor parameters (for example, temperature,pressure, and/or strain) along a portion and/or the entire length of aheater assembly. In certain embodiments, an optical sensor is used tomonitor composition of gas at one or more locations along the opticalsensor. The optical sensor may include, but is not limited to, a hightemperature rated optical fiber (for example, a single mode fiber or amultimode fiber) or fiber optic cable. A Sensornet DTS system(Sensornet; London, U.K.) includes an optical fiber that is used tomonitor temperature along a length of a heater assembly. A Sensomet DTSsystem includes an optical fiber that is used to monitor temperature andstrain (and/or pressure) at the same time along a length of a heaterassembly.

In some embodiments, an optical sensor used to monitor temperature,strain, and/or pressure is protected by positioning, at least partially,the optical sensor in a protective sleeve (such as an enclosed tube)resistant to conditions in a downhole environment. In certainembodiments, the protective sleeve is a small stainless steel tube. Insome embodiments, an open-ended sleeve is used to allow determination ofgas composition at the surface and/or at the terminal end of an oxidizerassembly. The optical sensor may be pre-installed in a protective sleeveand coiled on a reel. The sleeve may be uncoiled from the reel andcoupled to a heater assembly. In some embodiments, an optical sensor ina protective sleeve is lowered into a section of the formation with aheater assembly.

In certain embodiments, the sleeve is placed down a hollow conductor ofa conductor-in-conduit heater. In some embodiments, the fiber opticcable is a high temperature rated fiber optic cable. FIG. 79 depicts anembodiment of sleeve 708 in a conductor-in-conduit heater. Conductor 666may be a hollow conductor. Sleeve 708 may be placed inside conductor666. Sleeve 708 may be moved to a position inside conductor 666 byproviding a pressurized fluid (for example, a pressurized inert gas)into the conductor to move the sleeve along a length of the conductor.Sleeve 708 may have a plug 710 located at an end of the sleeve so thatthe sleeve is moved by the pressurized fluid. Plug 710 may be of adiameter slightly smaller than an inside diameter of conductor 666 sothat the plug is allowed to move along the inside of the conductor. Insome embodiments, plug 710 has small openings to allow some fluid toflow past the plug. Conductor 666 may have an open end or a closed endwith openings at the end to allow pressure release from the end of theconductor so that sleeve 708 and plug 710 can move along the inside ofthe conductor. Sleeve 708 may be placed inside any hollow conduit orconductor in any type of heater.

Using a pressurized fluid to position sleeve 708 inside conductor 666allows for selected positioning of the sleeve. The pressure of the fluidused to move sleeve 708 inside conductor 666 may be set to move thesleeve a selected distance in the conductor so that the sleeve ispositioned as desired. In certain embodiments, sleeve 708 may beremovable from conductor 666 so that the sleeve can be repaired and/orreplaced.

Temperatures monitored by the fiber optic cable may depend uponpositioning of sleeve 708. In certain embodiments, sleeve 708 ispositioned in an annulus between the conduit and the conductor orbetween the conduit and an opening in the formation. In certainembodiments, sleeve 708 with enclosed fiber optic cable is wrappedspirally to enhance resolution.

In certain embodiments, centralizers (such as centralizers 672 depictedin FIGS. 75 and 76) are made of silicon nitride. In some embodiments,silicon nitride is gas pressure sintered reaction bonded siliconnitride. Gas pressure sintered reaction bonded silicon nitride can bemade by sintering the silicon nitride at 1800° C. in a 10.3 MPa nitrogenatmosphere to inhibit degradation of the silicon nitride duringsintering. One example of a gas pressure sintered reaction bondedsilicon nitride is obtained from Ceradyne, Inc. (Costa Mesa, Calif.,U.S.A.) as Ceralloy® 147-31N.

Gas pressure sintered reaction bonded silicon nitride may be ground to afine finish. The fine finish (which gives a very low surface porosity ofthe silicon nitride) allows the silicon nitride to slide easily alongmetal surfaces without picking up metal particles from the surfaces. Gaspressure sintered reaction bonded silicon nitride is a very densematerial with high tensile strength, high flexural mechanical strength,and high thermal impact stress characteristics. Gas pressure sinteredreaction bonded silicon nitride is an excellent high temperatureelectrical insulator. Gas pressure sintered reaction bonded siliconnitride has about the same leakage current at 900° C. as alumina (Al₂O₃)at 760° C. Gas pressure sintered reaction bonded silicon nitride has athermal conductivity of 25 watts per meter·K. The relatively highthermal conductivity promotes heat transfer away from the centerconductor of a conductor-in-conduit heater.

Other types of silicon nitride such as, but not limited to,reaction-bonded silicon nitride or hot isostatically pressed siliconnitride may be used. Hot isostatic pressing includes sintering granularsilicon nitride and additives at 100-200 MPa in nitrogen gas. Somesilicon nitrides are made by sintering silicon nitride with yttriumoxide or cerium oxide to lower the sintering temperature so that thesilicon nitride does not degrade (for example, by releasing nitrogen)during sintering. However, adding other material to the silicon nitridemay increase the leakage current of the silicon nitride at elevatedtemperatures compared to purer forms of silicon nitride.

FIG. 80 depicts an embodiment of a conductor-in-conduit temperaturelimited heater. Conductor 666 is coupled to ferromagnetic conductor 654(for example, clad, coextruded, press fit, drawn inside). In someembodiments, ferromagnetic conductor 654 is coextruded over conductor666. Ferromagnetic conductor 654 is coupled to the outside of conductor666 so that current propagates only through the skin depth of theferromagnetic conductor at room temperature. Ferromagnetic conductor 654provides mechanical support for conductor 666 at elevated temperatures.Ferromagnetic conductor 654 is, for example, iron, iron alloy, or anyother ferromagnetic material. In an embodiment, conductor 666 is copperand ferromagnetic conductor 654 is 446 stainless steel.

Conductor 666 and ferromagnetic conductor 654 are electrically coupledto conduit 668 with sliding connector 678. Conduit 668 is anon-ferromagnetic material such as, but not limited to, 347H stainlesssteel. In one embodiment, conduit 668 is a 1½″ Schedule 80 347Hstainless steel pipe. In another embodiment, conduit 668 is a ScheduleXXH 347H stainless steel pipe. One or more centralizers 672 maintain thegap between conduit 668 and ferromagnetic conductor 654. In anembodiment, centralizer 672 is made of gas pressure sintered reactionbonded silicon nitride. Centralizer 672 may be held in position onferromagnetic conductor 654 by one or more weld tabs located on theferromagnetic conductor.

In certain embodiments, the composite electrical conductor may be usedas a conductor in an insulated conductor heater. FIG. 81A and FIG. 81Bdepict an embodiment of the insulated conductor heater. Insulatedconductor 712 includes core 656 and inner conductor 626. Core 656 andinner conductor 626 are a composite electrical conductor. Core 656 andinner conductor 626 are located within insulator 628. Core 656, innerconductor 626, and insulator 628 are located inside outer conductor 630.Insulator 628 is silicon nitride, boron nitride, magnesium oxide, oranother suitable electrical insulator. Outer conductor 630 is copper,steel, or any other electrical conductor.

In certain embodiments, insulator 628 is a powdered insulator. In someembodiments, insulator 628 is an insulator with a preformed shape (forexample, preformed half-shells). Insulated conductor 712 may be formedusing several techniques known in the art. Examples of techniques forforming insulated conductors include a “weld-fill-draw” method or a“fill-draw” method. Insulated conductors made using these techniques maybe made by, for example, Tyco International, Inc. (Princeton, N.J.,U.S.A.) or Watlow Electric Manufacturing Co. (St. Louis, Mo., U.S.A.).

In some embodiments, jacket 636 is located outside outer conductor 630,as shown in FIG. 82A and FIG. 82B. In some embodiments, jacket 636 is304 stainless steel and outer conductor 630 is copper. Jacket 636provides corrosion resistance for the insulated conductor heater. Insome embodiments, jacket 636 and outer conductor 630 are preformedstrips that are drawn over insulator 628 to form insulated conductor712.

In certain embodiments, insulated conductor 712 is located in a conduitthat provides protection (for example, corrosion protection, degradationprotection, and mechanical deformation protection) for the insulatedconductor. In FIG. 83, insulated conductor 712 is located inside conduit668 with gap 714 separating the insulated conductor from the conduit.

For a temperature limited heater in which the ferromagnetic conductorprovides a majority of the resistive heat output below the Curietemperature, a majority of the current flows through material withhighly non-linear functions of magnetic field (H) versus magneticinduction (B). These non-linear functions may cause strong inductiveeffects and distortion that lead to decreased power factor in thetemperature limited heater at temperatures below the Curie temperature.These effects may render the electrical power supply to the temperaturelimited heater difficult to control and may result in additional currentflow through surface and/or overburden power supply conductors.Expensive and/or difficult to implement control systems such as variablecapacitors or modulated power supplies may be used to attempt tocompensate for these effects and to control temperature limited heaterswhere the majority of the resistive heat output is provided by currentflow through the ferromagnetic material.

In certain temperature limited heater embodiments, the ferromagneticconductor confines a majority of the flow of electrical current to anelectrical conductor coupled to the ferromagnetic conductor when thetemperature limited heater is below or near the Curie temperature of theferromagnetic conductor. The electrical conductor may be a sheath,jacket, support member, corrosion resistant member, or otherelectrically resistive member. In some embodiments, the ferromagneticconductor confines a majority of the flow of electrical current to theelectrical conductor positioned between an outermost layer and theferromagnetic conductor. The ferromagnetic conductor is located in thecross section of the temperature limited heater such that the magneticproperties of the ferromagnetic conductor at or below the Curietemperature of the ferromagnetic conductor confine the majority of theflow of electrical current to the electrical conductor. The majority ofthe flow of electrical current is confined to the electrical conductordue to the skin effect of the ferromagnetic conductor. Thus, themajority of the current is flowing through material with substantiallylinear resistive properties throughout most of the operating range ofthe heater.

In certain embodiments, the ferromagnetic conductor and the electricalconductor are located in the cross section of the temperature limitedheater so that the skin effect of the ferromagnetic material limits thepenetration depth of electrical current in the electrical conductor andthe ferromagnetic conductor at temperatures below the Curie temperatureof the ferromagnetic conductor. Thus, the electrical conductor providesa majority of the electrically resistive heat output of the temperaturelimited heater at temperatures up to a temperature at or near the Curietemperature of the ferromagnetic conductor. In certain embodiments, thedimensions of the electrical conductor may be chosen to provide desiredheat output characteristics.

Because the majority of the current flows through the electricalconductor below the Curie temperature, the temperature limited heaterhas a resistance versus temperature profile that at least partiallyreflects the resistance versus temperature profile of the material inthe electrical conductor. Thus, the resistance versus temperatureprofile of the temperature limited heater is substantially linear belowthe Curie temperature of the ferromagnetic conductor if the material inthe electrical conductor has a substantially linear resistance versustemperature profile. For example, the temperature limited heater inwhich the majority of the current flows in the electrical conductorbelow the Curie temperature may have a resistance versus temperatureprofile similar to the profile shown in FIG. 182. The resistance of thetemperature limited heater has little or no dependence on the currentflowing through the heater until the temperature nears the Curietemperature. The majority of the current flows in the electricalconductor rather than the ferromagnetic conductor below the Curietemperature.

Resistance versus temperature profiles for temperature limited heatersin which the majority of the current flows in the electrical conductoralso tend to exhibit sharper reductions in resistance near or at theCurie temperature of the ferromagnetic conductor. For example, thereduction in resistance shown in FIG. 182 is sharper than the reductionin resistance shown in FIG. 166. The sharper reductions in resistancenear or at the Curie temperature are easier to control than more gradualresistance reductions near the Curie temperature.

In certain embodiments, the material and/or the dimensions of thematerial in the electrical conductor are selected so that thetemperature limited heater has a desired resistance versus temperatureprofile below the Curie temperature of the ferromagnetic conductor.

Temperature limited heaters in which the majority of the current flowsin the electrical conductor rather than the ferromagnetic conductorbelow the Curie temperature are easier to predict and/or control.Behavior of temperature limited heaters in which the majority of thecurrent flows in the electrical conductor rather than the ferromagneticconductor below the Curie temperature may be predicted by, for example,its resistance versus temperature profile and/or its power factor versustemperature profile. Resistance versus temperature profiles and/or powerfactor versus temperature profiles may be assessed or predicted by, forexample, experimental measurements that assess the behavior of thetemperature limited heater, analytical equations that assess or predictthe behavior of the temperature limited heater, and/or simulations thatassess or predict the behavior of the temperature limited heater.

In certain embodiments, assessed or predicted behavior of thetemperature limited heater is used to control the temperature limitedheater. The temperature limited heater may be controlled based onmeasurements (assessments) of the resistance and/or the power factorduring operation of the heater. In some embodiments, the power, orcurrent, supplied to the temperature limited heater is controlled basedon assessment of the resistance and/or the power factor of the heaterduring operation of the heater and the comparison of this assessmentversus the predicted behavior of the heater. In certain embodiments, thetemperature limited heater is controlled without measurement of thetemperature of the heater or a temperature near the heater. Controllingthe temperature limited heater without temperature measurementeliminates operating costs associated with downhole temperaturemeasurement. Controlling the temperature limited heater based onassessment of the resistance and/or the power factor of the heater alsoreduces the time for making adjustments in the power or current suppliedto the heater compared to controlling the heater based on measuredtemperature.

As the temperature of the temperature limited heater approaches orexceeds the Curie temperature of the ferromagnetic conductor, reductionin the ferromagnetic properties of the ferromagnetic conductor allowselectrical current to flow through a greater portion of the electricallyconducting cross section of the temperature limited heater. Thus, theelectrical resistance of the temperature limited heater is reduced andthe temperature limited heater automatically provides reduced heatoutput at or near the Curie temperature of the ferromagnetic conductor.In certain embodiments, a highly electrically conductive member iscoupled to the ferromagnetic conductor and the electrical conductor toreduce the electrical resistance of the temperature limited heater at orabove the Curie temperature of the ferromagnetic conductor. The highlyelectrically conductive member may be an inner conductor, a core, oranother conductive member of copper, aluminum, nickel, or alloysthereof.

The ferromagnetic conductor that confines the majority of the flow ofelectrical current to the electrical conductor at temperatures below theCurie temperature may have a relatively small cross section compared tothe ferromagnetic conductor in temperature limited heaters that use theferromagnetic conductor to provide the majority of resistive heat outputup to or near the Curie temperature. A temperature limited heater thatuses the electrical conductor to provide a majority of the resistiveheat output below the Curie temperature has low magnetic inductance attemperatures below the Curie temperature because less current is flowingthrough the ferromagnetic conductor as compared to the temperaturelimited heater where the majority of the resistive heat output below theCurie temperature is provided by the ferromagnetic material. Magneticfield (H) at radius (r) of the ferromagnetic conductor is proportionalto the current (I) flowing through the ferromagnetic conductor and thecore divided by the radius, or:H∝I/r.  (4)Since only a portion of the current flows through the ferromagneticconductor for a temperature limited heater that uses the outer conductorto provide a majority of the resistive heat output below the Curietemperature, the magnetic field of the temperature limited heater may besignificantly smaller than the magnetic field of the temperature limitedheater where the majority of the current flows through the ferromagneticmaterial. The relative magnetic permeability (μ) may be large for smallmagnetic fields.

The skin depth (δ) of the ferromagnetic conductor is inverselyproportional to the square root of the relative magnetic permeability(μ):δ∝(1/μ)^(1/2).  (5)Increasing the relative magnetic permeability decreases the skin depthof the ferromagnetic conductor. However, because only a portion of thecurrent flows through the ferromagnetic conductor for temperatures belowthe Curie temperature, the radius (or thickness) of the ferromagneticconductor may be decreased for ferromagnetic materials with largerelative magnetic permeabilities to compensate for the decreased skindepth while still allowing the skin effect to limit the penetrationdepth of the electrical current to the electrical conductor attemperatures below the Curie temperature of the ferromagnetic conductor.The radius (thickness) of the ferromagnetic conductor may be between 0.3mm and 8 mm, between 0.3 mm and 2 mm, or between 2 mm and 4 mm dependingon the relative magnetic permeability of the ferromagnetic conductor.Decreasing the thickness of the ferromagnetic conductor decreases costsof manufacturing the temperature limited heater, as the cost offerromagnetic material tends to be a significant portion of the cost ofthe temperature limited heater. Increasing the relative magneticpermeability of the ferromagnetic conductor provides a higher turndownratio and a sharper decrease in electrical resistance for thetemperature limited heater at or near the Curie temperature of theferromagnetic conductor.

Ferromagnetic materials (such as purified iron or iron-cobalt alloys)with high relative magnetic permeabilities (for example, at least 200,at least 1000, at least 1×10⁴, or at least 1×10⁵) and/or high Curietemperatures (for example, at least 600° C., at least 700° C., or atleast 800° C.) tend to have less corrosion resistance and/or lessmechanical strength at high temperatures. The electrical conductor mayprovide corrosion resistance and/or high mechanical strength at hightemperatures for the temperature limited heater. Thus, the ferromagneticconductor may be chosen primarily for its ferromagnetic properties.

Confining the majority of the flow of electrical current to theelectrical conductor below the Curie temperature of the ferromagneticconductor reduces variations in the power factor. Because only a portionof the electrical current flows through the ferromagnetic conductorbelow the Curie temperature, the non-linear ferromagnetic properties ofthe ferromagnetic conductor have little or no effect on the power factorof the temperature limited heater, except at or near the Curietemperature. Even at or near the Curie temperature, the effect on thepower factor is reduced compared to temperature limited heaters in whichthe ferromagnetic conductor provides a majority of the resistive heatoutput below the Curie temperature. Thus, there is less or no need forexternal compensation (for example, variable capacitors or waveformmodification) to adjust for changes in the inductive load of thetemperature limited heater to maintain a relatively high power factor.

In certain embodiments, the temperature limited heater, which confinesthe majority of the flow of electrical current to the electricalconductor below the Curie temperature of the ferromagnetic conductor,maintains the power factor above 0.85, above 0.9, or above 0.95 duringuse of the heater. Any reduction in the power factor occurs only insections of the temperature limited heater at temperatures near theCurie temperature. Most sections of the temperature limited heater aretypically not at or near the Curie temperature during use. Thesesections have a high power factor that approaches 1.0. The power factorfor the entire temperature limited heater is maintained above 0.85,above 0.9, or above 0.95 during use of the heater even if some sectionsof the heater have power factors below 0.85.

Maintaining high power factors also allows for less expensive powersupplies and/or control devices such as solid state power supplies orSCRs (silicon controlled rectifiers). These devices may fail to operateproperly if the power factor varies by too large an amount because ofinductive loads. With the power factors maintained at the higher values;however, these devices may be used to provide power to the temperaturelimited heater. Solid state power supplies also have the advantage ofallowing fine tuning and controlled adjustment of the power supplied tothe temperature limited heater.

In some embodiments, transformers are used to provide power to thetemperature limited heater. Multiple voltage taps may be made into thetransformer to provide power to the temperature limited heater. Multiplevoltage taps allows the current supplied to switch back and forthbetween the multiple voltages. This maintains the current within a rangebound by the multiple voltage taps.

The highly electrically conductive member, or inner conductor, increasesthe turndown ratio of the temperature limited heater. In certainembodiments, thickness of the highly electrically conductive member isincreased to increase the turndown ratio of the temperature limitedheater. In some embodiments, the thickness of the electrical conductoris reduced to increase the turndown ratio of the temperature limitedheater. In certain embodiments, the turndown ratio of the temperaturelimited heater is between 11.1 and 10, between 2 and 8, or between 3 and6 (for example, the turndown ratio is at least 1.1, at least 2, or atleast 3).

FIG. 84 depicts an embodiment of a temperature limited heater in whichthe support member provides a majority of the heat output below theCurie temperature of the ferromagnetic conductor. Core 656 is an innerconductor of the temperature limited heater. In certain embodiments,core 656 is a highly electrically conductive material such as copper oraluminum. In some embodiments, core 656 is a copper alloy that providesmechanical strength and good electrically conductivity such as adispersion strengthened copper. In one embodiment, core 656 is Glidcop®(SCM Metal Products, Inc., Research Triangle Park, N.C., U.S.A.).Ferromagnetic conductor 654 is a thin layer of ferromagnetic materialbetween electrical conductor 716 and core 656. In certain embodiments,electrical conductor 716 is also support member 662. In certainembodiments, ferromagnetic conductor 654 is iron or an iron alloy. Insome embodiments, ferromagnetic conductor 654 includes ferromagneticmaterial with a high relative magnetic permeability. For example,ferromagnetic conductor 654 may be purified iron such as Armco ingotiron (AK Steel Ltd., United Kingdom). Iron with some impuritiestypically has a relative magnetic permeability on the order of 400.Purifying the iron by annealing the iron in hydrogen gas (H₂) at 1450°C. increases the relative magnetic permeability of the iron. Increasingthe relative magnetic permeability of ferromagnetic conductor 654 allowsthe thickness of the ferromagnetic conductor to be reduced. For example,the thickness of unpurified iron may be approximately 4.5 mm while thethickness of the purified iron is approximately 0.76 mm.

In certain embodiments, electrical conductor 716 provides support forferromagnetic conductor 654 and the temperature limited heater.Electrical conductor 716 may be made of a material that provides goodmechanical strength at temperatures near or above the Curie temperatureof ferromagnetic conductor 654. In certain embodiments, electricalconductor 716 is a corrosion resistant member. Electrical conductor 716(support member 662) may provide support for ferromagnetic conductor 654and corrosion resistance. Electrical conductor 716 is made from amaterial that provides desired electrically resistive heat output attemperatures up to and/or above the Curie temperature of ferromagneticconductor 654.

In an embodiment, electrical conductor 716 is 347H stainless steel. Insome embodiments, electrical conductor 716 is another electricallyconductive, good mechanical strength, corrosion resistant material. Forexample, electrical conductor 716 may be 304H, 316H, 347HH, NF709,Incoloy® 800H alloy (Inco Alloys International, Huntington, W. Va.,U.S.A.), Haynes® HR120® alloy, or Inconel® 617 alloy.

In some embodiments, electrical conductor 716 (support member 662)includes different alloys in different portions of the temperaturelimited heater. For example, a lower portion of electrical conductor 716(support member 662) is 347H stainless steel and an upper portion of theelectrical conductor (support member) is NF709. In certain embodiments,different alloys are used in different portions of the electricalconductor (support member) to increase the mechanical strength of theelectrical conductor (support member) while maintaining desired heatingproperties for the temperature limited heater.

In some embodiments, ferromagnetic conductor 654 includes differentferromagnetic conductors in different portions of the temperaturelimited heater. Different ferromagnetic conductors may be used indifferent portions of the temperature limited heater to vary the Curietemperature and, thus, the maximum operating temperature in thedifferent portions. In some embodiments, the Curie temperature in anupper portion of the temperature limited heater is lower than the Curietemperature in a lower portion of the heater. The lower Curietemperature in the upper portion increases the creep-rupture strengthlifetime in the upper portion of the heater.

In the embodiment depicted in FIG. 84, ferromagnetic conductor 654,electrical conductor 716, and core 656 are dimensioned so that the skindepth of the ferromagnetic conductor limits the penetration depth of themajority of the flow of electrical current to the support member whenthe temperature is below the Curie temperature of the ferromagneticconductor. Thus, electrical conductor 716 provides a majority of theelectrically resistive heat output of the temperature limited heater attemperatures up to a temperature at or near the Curie temperature offerromagnetic conductor 654. In certain embodiments, the temperaturelimited heater depicted in FIG. 84 is smaller (for example, an outsidediameter of 3 cm, 2.9 cm, 2.5 cm, or less) than other temperaturelimited heaters that do not use electrical conductor 716 to provide themajority of electrically resistive heat output. The temperature limitedheater depicted in FIG. 84 may be smaller because ferromagneticconductor 654 is thin as compared to the size of the ferromagneticconductor needed for a temperature limited heater in which the majorityof the resistive heat output is provided by the ferromagnetic conductor.

In some embodiments, the support member and the corrosion resistantmember are different members in the temperature limited heater. FIGS. 85and 86 depict embodiments of temperature limited heaters in which thejacket provides a majority of the heat output below the Curietemperature of the ferromagnetic conductor. In these embodiments,electrical conductor 716 is jacket 636. Electrical conductor 716,ferromagnetic conductor 654, support member 662, and core 656 (in FIG.85) or inner conductor 626 (in FIG. 86) are dimensioned so that the skindepth of the ferromagnetic conductor limits the penetration depth of themajority of the flow of electrical current to the thickness of thejacket. In certain embodiments, electrical conductor 716 is a materialthat is corrosion resistant and provides electrically resistive heatoutput below the Curie temperature of ferromagnetic conductor 654. Forexample, electrical conductor 716 is 825 stainless steel or 347Hstainless steel. In some embodiments, electrical conductor 716 has asmall thickness (for example, on the order of 0.5 mm).

In FIG. 85, core 656 is highly electrically conductive material such ascopper or aluminum. Support member 662 is 347H stainless steel oranother material with good mechanical strength at or near the Curietemperature of ferromagnetic conductor 654.

In FIG. 86, support member 662 is the core of the temperature limitedheater and is 347H stainless steel or another material with goodmechanical strength at or near the Curie temperature of ferromagneticconductor 654. Inner conductor 626 is highly electrically conductivematerial such as copper or aluminum.

In certain embodiments, middle conductor 658 in the temperature limitedheater with triaxial conductors, depicted in FIG. 67A and FIG. 67B,includes an electrical conductor in addition to the ferromagneticmaterial. The electrical conductor may be on the outside of middleconductor 658. The electrical conductor and the ferromagnetic materialare dimensioned so that the skin depth of the ferromagnetic materiallimits the penetration depth of the majority of the flow of electricalcurrent to the electrical conductor when the temperature is below theCurie temperature of the ferromagnetic material. The electricalconductor provides a majority of the electrically resistive heat outputof middle conductor 658 (and the triaxial temperature limited heater) attemperatures up to a temperature at or near the Curie temperature offerromagnetic conductor. The electrical conductor is made from amaterial that provides desired electrically resistive heat output attemperatures up to and/or above the Curie temperature of ferromagneticmember. For example, the electrical conductor is 347H stainless steel,304H, 316H, 347HH, NF709, Incoloy® 800H alloy, Haynes® HR120® alloy, orInconel® 617 alloy.

In certain embodiments, the materials and design of the temperaturelimited heater are chosen to allow use of the heater at hightemperatures (for example, above 850° C.). FIG. 87 depicts a hightemperature embodiment of the temperature limited heater. The heaterdepicted in FIG. 87 operates as a conductor-in-conduit heater with themajority of heat being generated in conduit 668. Theconductor-in-conduit heater may provide a higher heat output because themajority of heat is generated in conduit 668 rather than conductor 666.Having the heat generated in conduit 668 reduces heat losses associatedwith transferring heat between the conduit and conductor 666.

Core 656 and conductive layer 634 are copper. In some embodiments, core656 and conductive layer 634 are nickel if the operating temperatures isto be near or above the melting point of copper. Support members 662 areelectrically conductive materials with good mechanical strength at hightemperatures. Materials for support members 662 that withstand at leasta maximum temperature of about 870° C. may be, but are not limited to,MO-RE® alloys (Duraloy Technologies, Inc. (Scottdale, Pa., U.S.A.)),CF8C+ (Metaltek Intl. (Waukesha, Wis., U.S.A.)), or Inconel® 617 alloy.Materials for support members 662 that withstand at least a maximumtemperature of about 980° C. include, but are not limited to, Incoloy®Alloy MA 956. Support member 662 in conduit 668 provides mechanicalsupport for the conduit. Support member 662 in conductor 666 providesmechanical support for core 656.

Electrical conductor 716 is a thin corrosion resistant material. Incertain embodiments, electrical conductor 716 is 347H, 617, 625, or 800Hstainless steel. Ferromagnetic conductor 654 is a high Curie temperatureferromagnetic material such as iron-cobalt alloy (for example, a 15% byweight cobalt, iron-cobalt alloy).

In certain embodiments, electrical conductor 716 provides the majorityof heat output of the temperature limited heater at temperatures up to atemperature at or near the Curie temperature of ferromagnetic conductor654. Conductive layer 634 increases the turndown ratio of thetemperature limited heater.

For long vertical temperature limited heaters (for example, heaters atleast 300 m, at least 500 m, or at least 1 km in length), the hangingstress becomes important in the selection of materials for thetemperature limited heater. Without the proper selection of material,the support member may not have sufficient mechanical strength (forexample, creep-rupture strength) to support the weight of thetemperature limited heater at the operating temperatures of the heater.FIG. 88 depicts hanging stress (ksi (kilopounds per square inch)) versusoutside diameter (in.) for the temperature limited heater shown in FIG.84 with 347H as the support member. The hanging stress was assessed withthe support member outside a 0.5″ copper core and a 0.75″ outsidediameter carbon steel ferromagnetic conductor. This assessment assumesthe support member bears the entire load of the heater and that theheater length is 1000 ft. (about 305 m). As shown in FIG. 88, increasingthe thickness of the support member decreases the hanging stress on thesupport member. Decreasing the hanging stress on the support memberallows the temperature limited heater to operate at higher temperatures.

In certain embodiments, materials for the support member are varied toincrease the maximum allowable hanging stress at operating temperaturesof the temperature limited heater and, thus, increase the maximumoperating temperature of the temperature limited heater. Altering thematerials of the support member affects the heat output of thetemperature limited heater below the Curie temperature because changingthe materials changes the resistance versus temperature profile of thesupport member. In certain embodiments, the support member is made ofmore than one material along the length of the heater so that thetemperature limited heater maintains desired operating properties (forexample, resistance versus temperature profile below the Curietemperature) as much as possible while providing sufficient mechanicalproperties to support the heater.

FIG. 89 depicts hanging stress (ksi) versus temperature (° F.) forseveral materials and varying outside diameters for the temperaturelimited heaters. Curve 718 is for 347H stainless steel. Curve 720 is forIncoloy® alloy 800H. Curve 722 is for Haynes® HR120® alloy. Curve 724 isfor NF709. Each of the curves includes four points that representvarious outside diameters of the support member. The point with thehighest stress for each curve corresponds to outside diameter of 1.05″.The point with the second highest stress for each curve corresponds tooutside diameter of 1.15″. The point with the second lowest stress foreach curve corresponds to outside diameter of 1.25″. The point with thelowest stress for each curve corresponds to outside diameter of 1.315″.As shown in FIG. 89, increasing the strength and/or outside diameter ofthe material and the support member increases the maximum operatingtemperature of the temperature limited heater.

FIGS. 90, 91, 92, and 93 depict examples of embodiments for temperaturelimited heaters able to provide desired heat output and mechanicalstrength for operating temperatures up to about 770° C. for 30,000 hrs.creep-rupture lifetime. The depicted temperature limited heaters havelengths of 1000 ft, copper cores of 0.5″ diameter, and ironferromagnetic conductors with outside diameters of 0.765″. In FIG. 90,the support member in heater portion 726 is 347H stainless steel. Thesupport member in heater portion 728 is Incoloy® alloy 800H. Portion 726has a length of 750 ft. and portion 728 has a length of 250 ft. Theoutside diameter of the support member is 1.315″. In FIG. 91, thesupport member in heater portion 726 is 347H stainless steel. Thesupport member in heater portion 728 is Incoloy® alloy 800H. The supportmember in heater portion 730 is Haynes® HR120® alloy. Portion 726 has alength of 650 ft., portion 728 has a length of 300 ft., and portion 730has a length of 50 ft. The outside diameter of the support member is1.15″. In FIG. 92, the support member in heater portion 726 is 347Hstainless steel. The support member in heater portion 728 is Incoloy®alloy 800H. The support member in heater portion 730 is Haynes® HR120®alloy. Portion 726 has a length of 550 ft., portion 728 has a length of250 ft., and portion 730 has a length of 200 ft. The outside diameter ofthe support member is 1.05″.

In some embodiments, a transition section is used between sections ofthe heater. For example, if one or more portions of the heater havevarying Curie temperatures, a transition section may be used betweenportions to provide strength that compensates for the differences intemperatures in the portions. FIG. 93 depicts another example of anembodiment of a temperature limited heater able to provide desired heatoutput and mechanical strength. The support member in heater portion 726is 347H stainless steel. The support member in heater portion 728 isNF709. The support member in heater portion 730 is 347H. Portion 726 hasa length of 550 ft. and a Curie temperature of 843° C., portion 728 hasa length of 250 ft. and a Curie temperature of 843° C., and portion 730has a length of 180 ft. and a Curie temperature of 770° C. Transitionsection 732 has a length of 20 ft., a Curie temperature of 770° C., andthe support member is NF709.

The materials of the support member along the length of the temperaturelimited heater may be varied to achieve a variety of desired operatingproperties. The choice of the materials of the temperature limitedheater is adjusted depending on a desired use of the temperature limitedheater. TABLE 1 lists examples of materials that may be used for thesupport member. The table provides the hanging stresses (a) of thesupport members and the maximum operating temperatures of thetemperature limited heaters for several different outside diameters (OD)of the support member. The core diameter and the outside diameter of theiron ferromagnetic conductor in each case are 0.5″ and 0.765″,respectively.

TABLE 1 OD = 1.05″ OD = 1.15″ OD = 1.25″ OD = 1.315″ Material σ (ksi) T(° F.) σ (ksi) T (° F.) σ (ksi) T (° F.) σ (ksi) T (° F.) 347H stainlesssteel 7.55 1310 6.33 1340 5.63 1360 5.31 1370 Incoloy ® alloy 800H 7.551337 6.33 1378 5.63 1400 5.31 1420 Haynes ® HR120 ® 7.57 1450 6.36 14925.65 1520 5.34 1540 alloy HA230 7.91 1475 6.69 1510 5.99 1530 5.67 1540Haynes ® alloy 556 7.65 1458 6.43 1492 5.72 1512 5.41 1520 NF709 7.571440 6.36 1480 5.65 1502 5.34 1512

In certain embodiments, one or more portions of the temperature limitedheater have varying outside diameters and/or materials to providedesired properties for the heater. FIGS. 94 and 95 depict examples ofembodiments for temperature limited heaters that vary the diameterand/or materials of the support member along the length of the heatersto provide desired operating properties and sufficient mechanicalproperties (for example, creep-rupture strength properties) foroperating temperatures up to about 834° C. for 30,000 hrs., heaterlengths of 850 ft, a copper core diameter of 0.5″, and an iron-cobalt(6% by weight cobalt) ferromagnetic conductor outside diameter of 0.75″.In FIG. 94, portion 726 is 347H stainless steel with a length of 300 ftand an outside diameter of 1.15″. Portion 728 is NF709 with a length of400 ft and an outside diameter of 1.15″. Portion 730 is NF709 with alength of 150 ft and an outside diameter of 1.25″. In FIG. 95, portion726 is 347H stainless steel with a length of 300 ft and an outsidediameter of 1.15″. Portion 728 is 347H stainless steel with a length of100 ft and an outside diameter of 1.20″. Portion 730 is NF709 with alength of 350 ft and an outside diameter of 1.20″. Portion 736 is NF709with a length of 100 ft and an outside diameter of 1.25″.

In certain embodiments, one or more portions of the temperature limitedheater have varying dimensions and/or varying materials to providedifferent power outputs along the length of the heater. More or lesspower output may be provided by varying the selected temperature (forexample, the Curie temperature) of the temperature limited heater byusing different ferromagnetic materials along its length and/or byvarying the electrical resistance of the heater by using differentdimensions in the heat generating member along the length of the heater.Different power outputs along the length of the temperature limitedheater may be needed to compensate for different thermal properties inthe formation adjacent to the heater. For example, an oil shaleformation may have different water-filled porosities, dawsonitecompositions, and/or nahcolite compositions at different depths in theformation. Portions of the formation with higher water-filledporosities, higher dawsonite compositions, and/or higher nahcolitecompositions may need more power input than portions with lowerwater-filled porosities, lower dawsonite compositions, and/or lowernahcolite compositions to achieve a similar heating rate. Power outputmay be varied along the length of the heater so that the portions of theformation with different properties (such as water-filled porosities,dawsonite compositions, and/or nahcolite compositions) are heated atapproximately the same heating rate.

In certain embodiments, portions of the temperature limited heater havedifferent selected self-limiting temperatures (for example, Curietemperatures), materials, and/or dimensions to compensate for varyingthermal properties of the formation along the length of the heater. Forexample, Curie temperatures, support member materials, and/or dimensionsof the portions of the heaters depicted in FIGS. 90-95 may be varied toprovide varying power outputs and/or operating temperatures along thelength of the heater.

As one example, in an embodiment of the temperature limited heaterdepicted in FIG. 90, portion 728 may be used to heat portions of theformation that, on average, have higher water-filled porosities,dawsonite compositions, and/or nahcolite compositions than portions ofthe formation heated by portion 726. Portion 728 may provide less poweroutput than portion 726 to compensate for the differing thermalproperties of the different portions of the formation so that the entireformation is heated at an approximately constant heating rate. Portion728 may require less power output because, for example, portion 728 isused to heat portions of the formation with low water-filled porositiesand/or little or no dawsonite. In one embodiment, portion 728 has aCurie temperature of 770° C. (pure iron) and portion 726 has a Curietemperature of 843° C. (iron with added cobalt). Such an embodiment mayprovide more power output from portion 726 so that the temperature lagbetween the two portions is reduced. Adjusting the Curie temperature ofportions of the heater adjusts the selected temperature at which theheater self-limits. In some embodiments, the dimensions of portion 728are adjusted to further reduce the temperature lag so that the formationis heated at an approximately constant heating rate throughout theformation. Dimensions of the heater may be adjusted to adjust theheating rate of one or more portions of the heater. For example, thethickness of an outer conductor in portion 728 may be increased relativeto the ferromagnetic member and/or the core of the heater so that theportion has a higher electrical resistance and the portion provides ahigher power output below the Curie temperature of the portion.

Reducing the temperature lag between different portions of the formationmay reduce the overall time needed to bring the formation to a desiredtemperature. Reducing the time needed to bring the formation to thedesired temperature reduces heating costs and produces desirableproduction fluids more quickly.

Temperature limited heaters with varying Curie temperatures may alsohave varying support member materials to provide mechanical strength forthe heater (for example, to compensate for hanging stress of the heaterand/or provide sufficient creep-rupture strength properties). Forexample, in the embodiment of the temperature limited heater depicted inFIG. 93, portions 726 and 728 have a Curie temperature of 843° C.Portion 726 has a support member made of 347H stainless steel. Portion728 has a support member made of NF709. Portion 730 has a Curietemperature of 770° C. and a support member made of 347H stainlesssteel. Transition section 732 has a Curie temperature of 770° C. and asupport member made of NF709. Transition section 732 may be short inlength compared to portions 726, 728, and 730. Transition section 732may be placed between portions 728 and 730 to compensate for thetemperature and material differences between the portions. For example,transition section 732 may be used to compensate for differences increep properties between portions 728 and 730.

Such a substantially vertical temperature limited heater may have lessexpensive, lower strength materials in portion 730 because of the lowerCurie temperature in this portion of the heater. For example, 347Hstainless steel may be used for the support member because of the lowermaximum operating temperature of portion 730 as compared to portion 728.Portion 728 may require the more expensive, higher strength materialbecause of the higher operating temperature of portion 728 due to thehigher Curie temperature in this portion.

In some embodiments, a relatively thin conductive layer is used toprovide the majority of the electrically resistive heat output of thetemperature limited heater at temperatures up to a temperature at ornear the Curie temperature of the ferromagnetic conductor. Such atemperature limited heater may be used as the heating member in aninsulated conductor heater. The heating member of the insulatedconductor heater may be located inside a sheath with an insulation layerbetween the sheath and the heating member.

FIGS. 96A and 96B depict cross-sectional representations of anembodiment of the insulated conductor heater with the temperaturelimited heater as the heating member. Insulated conductor 712 includescore 656, ferromagnetic conductor 654, inner conductor 626, electricalinsulator 628, and jacket 636. Core 656 is a copper core. Ferromagneticconductor 654 is, for example, iron or an iron alloy.

Inner conductor 626 is a relatively thin conductive layer ofnon-ferromagnetic material with a higher electrical conductivity thanferromagnetic conductor 654. In certain embodiments, inner conductor 626is copper. Inner conductor 626 may also be a copper alloy. Copper alloystypically have a flatter resistance versus temperature profile than purecopper. A flatter resistance versus temperature profile may provide lessvariation in the heat output as a function of temperature up to theCurie temperature. In some embodiments, inner conductor 626 is copperwith 6% by weight nickel (for example, CuNi6 or LOHM™). In someembodiments, inner conductor 626 is CuNi10Fe1Mn alloy. Below the Curietemperature of ferromagnetic conductor 654, the magnetic properties ofthe ferromagnetic conductor confine the majority of the flow ofelectrical current to inner conductor 626. Thus, inner conductor 626provides the majority of the resistive heat output of insulatedconductor 712 below the Curie temperature.

In certain embodiments, inner conductor 626 is dimensioned, along withcore 656 and ferromagnetic conductor 654, so that the inner conductorprovides a desired amount of heat output and a desired turndown ratio.For example, inner conductor 626 may have a cross-sectional area that isaround 2 or 3 times less than the cross-sectional area of core 656.Typically, inner conductor 626 has to have a relatively smallcross-sectional area to provide a desired heat output if the innerconductor is copper or copper alloy. In an embodiment with copper innerconductor 626, core 656 has a diameter of 0.66 cm, ferromagneticconductor 654 has an outside diameter of 0.91 cm, inner conductor 626has an outside diameter of 1.03 cm, electrical insulator 628 has anoutside diameter of 1.53 cm, and jacket 636 has an outside diameter of1.79 cm. In an embodiment with a CuNi6 inner conductor 626, core 656 hasa diameter of 0.66 cm, ferromagnetic conductor 654 has an outsidediameter of 0.91 cm, inner conductor 626 has an outside diameter of 1.12cm, electrical insulator 628 has an outside diameter of 1.63 cm, andjacket 636 has an outside diameter of 1.88 cm. Such insulated conductorsare typically smaller and cheaper to manufacture than insulatedconductors that do not use the thin inner conductor to provide themajority of heat output below the Curie temperature.

Electrical insulator 628 may be magnesium oxide, aluminum oxide, silicondioxide, beryllium oxide, boron nitride, silicon nitride, orcombinations thereof. In certain embodiments, electrical insulator 628is a compacted powder of magnesium oxide. In some embodiments,electrical insulator 628 includes beads of silicon nitride.

In certain embodiments, a small layer of material is placed betweenelectrical insulator 628 and inner conductor 626 to inhibit copper frommigrating into the electrical insulator at higher temperatures. Forexample, the small layer of nickel (for example, about 0.5 mm of nickel)may be placed between electrical insulator 628 and inner conductor 626.

Jacket 636 is made of a corrosion resistant material such as, but notlimited to, 347 stainless steel, 347H stainless steel, 446 stainlesssteel, or 825 stainless steel. In some embodiments, jacket 636 providessome mechanical strength for insulated conductor 712 at or above theCurie temperature of ferromagnetic conductor 654. In certainembodiments, jacket 636 is not used to conduct electrical current.

In certain embodiments of temperature limited heaters, three temperaturelimited heaters are coupled together in a three-phase wye configuration.Coupling three temperature limited heaters together in the three-phasewye configuration lowers the current in each of the individualtemperature limited heaters because the current is split between thethree individual heaters. Lowering the current in each individualtemperature limited heater allows each heater to have a small diameter.The lower currents allow for higher relative magnetic permeabilities ineach of the individual temperature limited heaters and, thus, higherturndown ratios. In addition, there may be no return current needed foreach of the individual temperature limited heaters. Thus, the turndownratio remains higher for each of the individual temperature limitedheaters than if each temperature limited heater had its own returncurrent path.

In the three-phase wye configuration, individual temperature limitedheaters may be coupled together by shorting the sheaths, jackets, orcanisters of each of the individual temperature limited heaters to theelectrically conductive sections (the conductors providing heat) attheir terminating ends (for example, the ends of the heaters at thebottom of a heater wellbore). In some embodiments, the sheaths, jackets,canisters, and/or electrically conductive sections are coupled to asupport member that supports the temperature limited heaters in thewellbore.

FIG. 97A depicts an embodiment for installing and coupling heaters in awellbore. The embodiment in FIG. 97A depicts insulated conductor heatersbeing installed into the wellbore. Other types of heaters, such asconductor-in-conduit heaters, may also be installed in the wellboreusing the embodiment depicted. Also, in FIG. 97A, two insulatedconductors 712 are shown while a third insulated conductor is not seenfrom the view depicted. Typically, three insulated conductors 712 wouldbe coupled to support member 738, as shown in FIG. 97B. In anembodiment, support member 738 is a thick walled 347H pipe. In someembodiments, thermocouples or other temperature sensors are placedinside support member 738. The three insulated conductors may be coupledin a three-phase wye configuration.

In FIG. 97A, insulated conductors 712 are coiled on coiled tubing rigs740. As insulated conductors 712 are uncoiled from rigs 740, theinsulated conductors are coupled to support member 738. In certainembodiments, insulated conductors 712 are simultaneously uncoiled and/orsimultaneously coupled to support member 738. Insulated conductors 712may be coupled to support member 738 using metal (for example, 304stainless steel or Inconel® alloys) straps 742. In some embodiments,insulated conductors 712 are coupled to support member 738 using othertypes of fasteners such as buckles, wire holders, or snaps. Supportmember 738 along with insulated conductors 712 are installed intoopening 378. In some embodiments, insulated conductors 712 are coupledtogether without the use of a support member. For example, one or morestraps 742 may be used to couple insulated conductors 712 together.

Insulated conductors 712 may be electrically coupled to each other at alower end of the insulated conductors. In a three-phase wyeconfiguration, insulated conductors 712 operate without a current returnpath. In certain embodiments, insulated conductors 712 are electricallycoupled to each other in contactor section 744. In section 744, sheaths,jackets, canisters, and/or electrically conductive sections areelectrically coupled to each other and/or to support member 738 so thatinsulated conductors 712 are electrically coupled in the section.

In certain embodiments, the sheaths of insulated conductors 712 areshorted to the conductors of the insulated conductors. FIG. 97C depictsan embodiment of insulated conductor 712 with the sheath shorted to theconductors. Sheath 636 is electrically coupled to core 656,ferromagnetic conductor 654, and inner conductor 626 using termination746. Termination 746 may be a metal strip or a metal plate at the lowerend of insulated conductor 712. For example, termination 746 may be acopper plate coupled to sheath 636, core 656, ferromagnetic conductor654, and inner conductor 626 so that they are shorted together. In someembodiments, termination 746 is welded or brazed to sheath 636, core656, ferromagnetic conductor 654, and inner conductor 626.

The sheaths of individual insulated conductors 712 may be shortedtogether to electrically couple the conductors of the insulatedconductors, depicted in FIGS. 97A and 97B. In some embodiments, thesheaths may be shorted together because the sheaths are in physicalcontact with each other. For example, the sheaths may in physicalcontact if the sheaths are strapped together by straps 742. In someembodiments, the lower ends of the sheaths are physically coupled (forexample, welded) at the surface of opening 378 before insulatedconductors 712 are installed into the opening.

In certain embodiments, three conductors are located inside a singleconduit to form a three conductor-in-conduit heater. FIGS. 98A and 98Bdepict an embodiment of a three conductor-in-conduit heater. FIG. 98Adepicts a top down view of the three conductor-in-conduit heater. FIG.98B depicts a side view representation with a cutout to show theinternals of the three conductor-in-conduit heater. Three conductors 666are located inside conduit 668. The three conductors 666 aresubstantially evenly spaced within conduit 668. In some embodiments, thethree conductors 666 are coupled in a spiral configuration.

One or more centralizers 672 are placed around each conductor 666.Centralizers 672 are made from electrically insulating material such assilicon nitride or boron nitride. Centralizers 672 maintain a positionof conductors 666 in conduit 668. Centralizers 672 also inhibitelectrical contact between conductors 666 and conduit 668. In certainembodiments, centralizers 672 are spaced along the length of conductors666 so that the centralizers surrounding one conductor overlap (as seenfrom the top down view) centralizers from another conductor. Thisreduces the number of centralizers needed for each conductor and allowsfor tight spacing of the conductors.

In certain embodiments, the three conductors 666 are coupled in athree-phase wye configuration. The three conductors 666 may be coupledat or near the bottom of the heaters in the three-phase wyeconfiguration. In the three-phase wye configuration, conduit 668 is notelectrically coupled to the three conductors 666. Thus, conduit 668 mayonly be used to provide strength for and/or inhibit corrosion of thethree conductors 666.

In some embodiments, a long temperature limited heater (for example, atemperature limited heater in which the support member provides amajority of the heat output below the Curie temperature of theferromagnetic conductor) is formed from several sections of heater. Thesections of heater may be coupled using a welding process. FIG. 99depicts an embodiment for coupling together sections of a longtemperature limited heater. Ends of ferromagnetic conductors 654 andends of electrical conductors 716 (support members 662) are beveled tofacilitate coupling the sections of the heater. Core 656 has recesses toallow core coupling material 650 to be placed inside the abutted ends ofthe heater. Core coupling material 650 may be a pin or dowel that fitstightly in the recesses of cores 656. Core coupling material 650 may bemade out of the same material as cores 656 or a material suitable forcoupling the cores together. Core coupling material 650 allows theheaters to be coupled together without welding cores 656 together. Cores656 are coupled together as a “pin” or “box” joint.

Beveled ends of ferromagnetic conductors 654 and electrical conductors716 may be coupled together with coupling material 660. In certainembodiments, ends of ferromagnetic conductors 654 and electricalconductors 716 are welded (for example, orbital welded) together.Coupling material 660 may be 625 stainless steel or any other suitablenon-ferromagnetic material for welding together ferromagnetic conductors654 and/or electrical conductors 716. Using beveled ends when couplingtogether sections of the heater may produce a reliable and durablecoupling between the sections of the heater.

During heating with the temperature limited heater, core couplingmaterial 650 may expand more radially than ferromagnetic conductors 654,electrical conductors 716, and/or coupling material 660. The greaterexpansion of core coupling material 650 maintains good electricalcontact with the core coupling material. At the coupling junction of theheater, electricity flows through core coupling material 650 rather thancoupling material 660. This flow of electricity inhibits heat generationat the coupling junction so that the junction remains at lowertemperatures than other portions of the heater during application ofelectrical current to the heater. The corrosion resistance and strengthof the coupling junction is increased by maintaining the junction atlower temperatures.

In certain embodiments, the junction may be enclosed in a shield duringorbital welding to ensure reliability of the weld. If the junction isnot enclosed, disturbance of the inert gas caused by wind, humidity orother conditions may cause oxidation and/or porosity of the weld.Without a shield, a first portion of the weld was formed and allowed tocool. A grinder would be used to remove the oxide layer. The processwould be repeated until the weld was complete. Enclosing the junction inthe shield with an inert gas allows the weld to be formed with nooxidation, thus allowing the weld to be formed in one pass with no needfor grinding. Enclosing the junction increases the safety of forming theweld because the arc of the orbital welder is enclosed in the shieldduring welding. Enclosing the junction in the shield may reduce the timeneeded to form the weld. Without a shield, producing each weld may take30 minutes or more. With the shield, each weld may take 10 minutes orless.

FIG. 100 depicts an embodiment of a shield for orbital welding sectionsof a long temperature limited heater. Orbital welding may also be usedto form canisters for freeze wells from sections of pipe. Shield 748 mayinclude upper plate 750, lower plate 752, inserts 754, wall 756, hingeddoor 758, first clamp member 760, and second clamp member 762. Wall 756may include one or more inert gas inlets. Wall 756, upper plate 750,and/or lower plate 752 may include one or more openings for monitoringequipment or gas purging. Shield 748 is configured to work with anorbital welder, such as AMI Power Supply (Model 227) and AMI OrbitalWeld Head (Model 97-2375) available from Arc Machines, Inc. (Pacoima,Calif., U.S.A.). Inserts 754 may be withdrawn from upper plate 750 andlower plate 752. The orbital weld head may be positioned in shield 748.Shield 748 may be placed around a lower conductor of the conductors thatare to be welded together. When shield is positioned so that the end ofthe lower conductor is at a desired position in the middle of theshield, first clamp member may be fastened to second clamp member tosecure shield 748 to the lower conductor. The upper conductor may bepositioned in shield 748. Inserts 754 may be placed in upper plate 750and lower plate 752.

Hinged door 758 may be closed. The orbital welder may be used to weldthe lower conductor to the upper conductor. Progress of the weldingoperation may be monitored through viewing windows 764. When the weld iscomplete, shield 748 may be supported and first clamp member 760 may beunfastened from second clamp member 762. One or both inserts 754 may beremoved or partially removed from lower plate 752 and upper plate 750 tofacilitate lowering of the conductor. The conductor may be lowered inthe wellbore until the end of the conductor is located at a desiredposition in shield 748. Shield 748 may be secured to the conductor withfirst clamp member 760 and second clamp member 762. Another conductormay be positioned in the shield. Inserts 754 may be positioned in upperand lower plates 750, 752, hinged door is closed 758, and the orbitalwelder is used to weld the conductors together. The process may berepeated until a desired length of conductor is formed.

The shield may be used to weld joints of pipe over an opening in thehydrocarbon containing formation. Hydrocarbon vapors from the formationmay create an explosive atmosphere in the shield even though the inertgas supplied to the shield inhibits the formation of dangerousconcentrations of hydrocarbons in the shield. A control circuit may becoupled to a power supply for the orbital welder to stop power to theorbital welder to shut off the arc forming the weld if the hydrocarbonlevel in the shield rises above a selected concentration. FIG. 101depicts a schematic representation of a shut off circuit for orbitalwelding machine 766. An inert gas, such as argon, may enter shield 748through inlet 768. Gas may exit shield 748 through purge 770. Powersupply 772 supplies electricity to orbital welding machine 766 throughlines 774, 776. Switch 778 may be located in line 774 to orbital weldingmachine 766. Switch 778 may be electrically coupled to hydrocarbonmonitor 780. Hydrocarbon monitor 780 may detect the hydrocarbonconcentration in shield 748. If the hydrocarbon concentration in shieldbecomes too high, for example, over 25% of a lower explosion limitconcentration, hydrocarbon monitor 780 may open switch 778. When switch778 is open, power to orbital welder 766 is interrupted and the arcformed by the orbital welder ends.

In some embodiments, the temperature limited heater is used to achievelower temperature heating (for example, for heating fluids in aproduction well, heating a surface pipeline, or reducing the viscosityof fluids in a wellbore or near wellbore region). Varying theferromagnetic materials of the temperature limited heater allows forlower temperature heating. In some embodiments, the ferromagneticconductor is made of material with a lower Curie temperature than thatof 446 stainless steel. For example, the ferromagnetic conductor may bean alloy of iron and nickel. The alloy may have between 30% by weightand 42% by weight nickel with the rest being iron. In one embodiment,the alloy is Invar 36. Invar 36 is 36% by weight nickel in iron and hasa Curie temperature of 277° C. In some embodiments, an alloy is a threecomponent alloy with, for example, chromium, nickel, and iron. Forexample, an alloy may have 6% by weight chromium, 42% by weight nickel,and 52% by weight iron. A 2.5 cm diameter rod of Invar 36 has a turndownratio of approximately 2 to 1 at the Curie temperature. Placing theInvar 36 alloy over a copper core may allow for a smaller rod diameter.A copper core may result in a high turndown ratio. The insulator inlower temperature heater embodiments may be made of a high performancepolymer insulator (such as PFA or PEEK™) when used with alloys with aCurie temperature that is below the melting point or softening point ofthe polymer insulator.

In certain embodiments, a conductor-in-conduit temperature limitedheater is used in lower temperature applications by using lower Curietemperature ferromagnetic materials. For example, a lower Curietemperature ferromagnetic material may be used for heating inside suckerpump rods. Heating sucker pump rods may be useful to lower the viscosityof fluids in the sucker pump or rod and/or to maintain a lower viscosityof fluids in the sucker pump rod. Lowering the viscosity of the oil mayinhibit sticking of a pump used to pump the fluids. Fluids in the suckerpump rod may be heated up to temperatures less than about 250° C. orless than about 300° C. Temperatures need to be maintained below thesevalues to inhibit coking of hydrocarbon fluids in the sucker pumpsystem.

For lower temperature applications, ferromagnetic conductor 654 in FIG.80 may be Alloy 42-6 coupled to conductor 666. Conductor 666 may becopper. In one embodiment, ferromagnetic conductor 654 is 1.9 cm outsidediameter Alloy 42-6 over copper conductor 666 with a 2:1 outsidediameter to copper diameter ratio. In some embodiments, ferromagneticconductor 654 includes other lower temperature ferromagnetic materialssuch as Alloy 32, Alloy 52, Invar 36, iron-nickel-chromium alloys,iron-nickel alloys, nickel-chromium alloys, or other nickel alloys.Conduit 668 may be a hollow sucker rod made from carbon steel. Thecarbon steel or other material used in conduit 668 confines current tothe inside of the conduit to inhibit stray voltages at the surface ofthe formation. Centralizer 672 may be made from gas pressure sinteredreaction bonded silicon nitride. In some embodiments, centralizer 672 ismade from polymers such as PFA or PEEK™. In certain embodiments, polymerinsulation is clad along an entire length of the heater. Conductor 666and ferromagnetic conductor 654 are electrically coupled to conduit 668with sliding connector 678.

FIG. 102 depicts an embodiment of a temperature limited heater with alow temperature ferromagnetic outer conductor. Outer conductor 630 isglass sealing Alloy 42-6. Alloy 42-6 may be obtained from CarpenterMetals (Reading, Pa., U.S.A.) or Anomet Products, Inc. In someembodiments, outer conductor 630 includes other compositions and/ormaterials to get various Curie temperatures (for example, CarpenterTemperature Compensator “32” (Curie temperature of 199° C.; availablefrom Carpenter Metals) or Invar 36). In an embodiment, conductive layer634 is coupled (for example, clad, welded, or brazed) to outer conductor630. Conductive layer 634 is a copper layer. Conductive layer 634improves a turndown ratio of outer conductor 630. Jacket 636 is aferromagnetic metal such as carbon steel. Jacket 636 protects outerconductor 630 from a corrosive environment. Inner conductor 626 may haveelectrical insulator 628. Electrical insulator 628 may be a mica tapewinding with overlaid fiberglass braid. In an embodiment, innerconductor 626 and electrical insulator 628 are a 4/0 MGT-1000 furnacecable or 3/0 MGT-1000 furnace cable. 4/0 MGT-1000 furnace cable or 3/0MGT-1000 furnace cable is available from Allied Wire and Cable. In someembodiments, a protective braid such as a stainless steel braid may beplaced over electrical insulator 628.

Conductive section 632 electrically couples inner conductor 626 to outerconductor 630 and/or jacket 636. In some embodiments, jacket 636 touchesor electrically contacts conductive layer 634 (for example, if theheater is placed in a horizontal configuration). If jacket 636 is aferromagnetic metal such as carbon steel (with a Curie temperature abovethe Curie temperature of outer conductor 630), current will propagateonly on the inside of the jacket. Thus, the outside of the jacketremains electrically uncharged during operation. In some embodiments,jacket 636 is drawn down (for example, swaged down in a die) ontoconductive layer 634 so that a tight fit is made between the jacket andthe conductive layer. The heater may be spooled as coiled tubing forinsertion into a wellbore. In other embodiments, an annular space ispresent between conductive layer 634 and jacket 636, as depicted in FIG.102.

FIG. 103 depicts an embodiment of a temperature limitedconductor-in-conduit heater. Conduit 668 is a hollow sucker rod made ofa ferromagnetic metal such as Alloy 42-6, Alloy 32, Alloy 52, Invar 36,iron-nickel-chromium alloys, iron-nickel alloys, nickel alloys, ornickel-chromium alloys. Inner conductor 626 has electrical insulator628. Electrical insulator 628 is a mica tape winding with overlaidfiberglass braid. In an embodiment, inner conductor 626 and electricalinsulator 628 are a 4/0 MGT-1000 furnace cable or 3/0 MGT-1000 furnacecable. In some embodiments, polymer insulations are used for lowertemperature Curie heaters. In certain embodiments, a protective braid isplaced over electrical insulator 628. Conduit 668 has a wall thicknessthat is greater than the skin depth at the Curie temperature (forexample, 2 to 3 times the skin depth at the Curie temperature). In someembodiments, a more conductive conductor is coupled to conduit 668 toincrease the turndown ratio of the heater.

FIG. 104 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater. Conductor 666 iscoupled (for example, clad, coextruded, press fit, drawn inside) toferromagnetic conductor 654. A metallurgical bond between conductor 666and ferromagnetic conductor 654 is favorable. Ferromagnetic conductor654 is coupled to the outside of conductor 666 so that currentpropagates through the skin depth of the ferromagnetic conductor at roomtemperature. Conductor 666 provides mechanical support for ferromagneticconductor 654 at elevated temperatures. Ferromagnetic conductor 654 isiron, an iron alloy (for example, iron with 10% to 27% by weightchromium for corrosion resistance), or any other ferromagnetic material.In one embodiment, conductor 666 is 304 stainless steel andferromagnetic conductor 654 is 446 stainless steel. Conductor 666 andferromagnetic conductor 654 are electrically coupled to conduit 668 withsliding connector 678. Conduit 668 may be a non-ferromagnetic materialsuch as austenitic stainless steel.

FIG. 105 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater. Conduit 668 is coupledto ferromagnetic conductor 654 (for example, clad, press fit, or drawninside of the ferromagnetic conductor). Ferromagnetic conductor 654 iscoupled to the inside of conduit 668 to allow current to propagatethrough the skin depth of the ferromagnetic conductor at roomtemperature. Conduit 668 provides mechanical support for ferromagneticconductor 654 at elevated temperatures. Conduit 668 and ferromagneticconductor 654 are electrically coupled to conductor 666 with slidingconnector 678.

FIG. 106 depicts a cross-sectional view of an embodiment of aconductor-in-conduit temperature limited heater. Conductor 666 maysurround core 656. In an embodiment, conductor 666 is 347H stainlesssteel and core 656 is copper. Conductor 666 and core 656 may be formedtogether as a composite conductor. Conduit 668 may include ferromagneticconductor 654. In an embodiment, ferromagnetic conductor 654 is SumitomoHCM12A or 446 stainless steel. Ferromagnetic conductor 654 may have aSchedule XXH thickness so that the conductor is inhibited fromdeforming. In certain embodiments, conduit 668 also includes jacket 636.Jacket 636 may include corrosion resistant material that inhibitselectrons from flowing away from the heater and into a subsurfaceformation at higher temperatures (for example, temperatures near theCurie temperature of ferromagnetic conductor 654). For example, jacket636 may be about a 0.4 cm thick sheath of 410 stainless steel.Inhibiting electrons from flowing to the formation may increase thesafety of using the heater in the subsurface formation.

FIG. 107 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater with an insulatedconductor. Insulated conductor 712 may include core 656, electricalinsulator 628, and jacket 636. Jacket 636 may be made of a corrosionresistant material (for example, stainless steel). Endcap 642 may beplaced at an end of insulated conductor 712 to couple core 656 tosliding connector 678. Endcap 642 may be made of non-corrosive,electrically conducting materials such as nickel or stainless steel.Endcap 642 may be coupled to the end of insulated conductor 712 by anysuitable method (for example, welding, soldering, braising). Slidingconnector 678 may electrically couple core 656 and endcap 642 toferromagnetic conductor 654. Conduit 668 may provide support forferromagnetic conductor 654 at elevated temperatures.

FIG. 108 depicts a cross-sectional representation of an embodiment of aninsulated conductor-in-conduit temperature limited heater. Insulatedconductor 712 may include core 656, electrical insulator 628, and jacket636. Insulated conductor 712 may be coupled to ferromagnetic conductor654 with connector 784. Connector 784 may be made of non-corrosive,electrically conducting materials such as nickel or stainless steel.Connector 784 may be coupled to insulated conductor 712 and coupled toferromagnetic conductor 654 using suitable methods for electricallycoupling (for example, welding, soldering, braising). Insulatedconductor 712 may be placed along a wall of ferromagnetic conductor 654.Insulated conductor 712 may provide mechanical support for ferromagneticconductor 654 at elevated temperatures. In some embodiments, otherstructures (for example, a conduit) are used to provide mechanicalsupport for ferromagnetic conductor 654.

FIG. 109 depicts a cross-sectional representation of an embodiment of aninsulated conductor-in-conduit temperature limited heater. Insulatedconductor 712 may be coupled to endcap 642. Endcap 642 may be coupled tocoupling 786. Coupling 786 may electrically couple insulated conductor712 to ferromagnetic conductor 654. Coupling 786 may be a flexiblecoupling. For example, coupling 786 may include flexible materials (forexample, braided wire). Coupling 786 may be made of corrosion resistantmaterial such as nickel, stainless steel, and/or copper.

FIG. 110 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater with an insulatedconductor. Insulated conductor 712 includes core 656, electricalinsulator 628, and jacket 636. Jacket 636 is made of a highlyelectrically conductive material such as copper. Core 656 is made of alower temperature ferromagnetic material such as such as Alloy 42-6,Alloy 32, Invar 36, iron-nickel-chromium alloys, iron-nickel alloys,nickel alloys, or nickel-chromium alloys. In certain embodiments, thematerials of jacket 636 and core 656 are reversed so that the jacket isthe ferromagnetic conductor and the core is the highly conductiveportion of the heater. Ferromagnetic material used in jacket 636 or core656 may have a thickness greater than the skin depth at the Curietemperature (for example, 2 to 3 times the skin depth at the Curietemperature). Endcap 642 is placed at an end of insulated conductor 712to couple core 656 to sliding connector 678. Endcap 642 is made ofcorrosion resistant, electrically conducting materials such as nickel orstainless steel. In certain embodiments, conduit 668 is a hollow suckerrod made from, for example, carbon steel.

FIGS. 111 and 112 depict cross-sectional views of an embodiment of atemperature limited heater that includes an insulated conductor. FIG.111 depicts a cross-sectional view of an embodiment of the overburdensection of the temperature limited heater. The overburden section mayinclude insulated conductor 712 placed in conduit 668. Conduit 668 maybe 1¼″ Schedule 80 carbon steel pipe internally clad with copper in theoverburden section. Insulated conductor 712 may be a mineral insulatedcable or polymer insulated cable. Conductive layer 634 may be placed inthe annulus between insulated conductor 712 and conduit 668. Conductivelayer 634 may be approximately 2.5 cm diameter copper tubing. Theoverburden section may be coupled to the heating section of the heater.FIG. 112 depicts a cross-sectional view of an embodiment of a heatingsection of the temperature limited heater. Insulated conductor 712 inthe heating section may be a continuous portion of insulated conductor712 in the overburden section. Ferromagnetic conductor 654 may becoupled to conductive layer 634. In certain embodiments, conductivelayer 634 in the heating section is copper drawn over ferromagneticconductor 654 and coupled to conductive layer 634 in the overburdensection. Conduit 668 may include a heating section and an overburdensection. These two sections may be coupled to form conduit 668. Theheating section may be 1¼″ Schedule 80 347H stainless steel pipe. An endcap, or other suitable electrical connector, may couple ferromagneticconductor 654 to insulated conductor 712 at a lower end of the heater.The lower end of the heater is the end farthest from the point theheater enters the hydrocarbon layer from the overburden section.

FIGS. 113 and 114 depict cross-sectional views of an embodiment of atemperature limited heater that includes an insulated conductor. FIG.113 depicts a cross-sectional view of an embodiment of the overburdensection of the temperature limited heater. Insulated conductor 712 mayinclude core 656, electrical insulator 628, and jacket 636. Insulatedconductor 712 may have a diameter of about 1.5 cm. Core 656 may becopper. Electrical insulator 628 may be silicon nitride, boron nitride,or magnesium oxide. Jacket 636 may be copper in the overburden sectionto reduce heat losses. Conduit 668 may be 1″ Schedule 40 carbon steel inthe overburden section. Conductive layer 634 may be coupled to conduit668. Conductive layer 634 may be copper with a thickness of about 0.2 cmto reduce heat losses in the overburden section. Gap 714 may be anannular space between insulated conductor 712 and conduit 668. FIG. 114depicts a cross-sectional view of an embodiment of a heating section ofthe temperature limited heater. Insulated conductor 712 in the heatingsection may be coupled to insulated conductor 712 in the overburdensection. Jacket 636 in the heating section may be made of a corrosionresistant material (for example, 825 stainless steel). Ferromagneticconductor 654 may be coupled to conduit 668 in the overburden section.Ferromagnetic conductor 654 may be Schedule 160 409, 410, or 446stainless steel pipe. Gap 714 may be between ferromagnetic conductor 654and insulated conductor 712. An end cap, or other suitable electricalconnector, may couple ferromagnetic conductor 654 to insulated conductor712 at a distal end of the heater. The distal end of the heater is theend farthest from the overburden section.

In certain embodiments, a temperature limited heater includes a flexiblecable (for example, a furnace cable) as the inner conductor. Forexample, the inner conductor may be a 27% nickel-clad or stainlesssteel-clad stranded copper wire with four layers of mica tape surroundedby a layer of ceramic and/or mineral fiber (for example, alumina fiber,aluminosilicate fiber, borosilicate fiber, or aluminoborosilicatefiber). A stainless steel-clad stranded copper wire furnace cable may beavailable from Anomet Products, Inc. The inner conductor may be ratedfor applications at temperatures of 1000° C. or higher. The innerconductor may be pulled inside a conduit. The conduit may be aferromagnetic conduit (for example, a ¾″ Schedule 80 446 stainless steelpipe). The conduit may be covered with a layer of copper, or otherelectrical conductor, With a thickness of about 0.3 cm or any othersuitable thickness. The assembly may be placed inside a support conduit(for example, a 1¼″ Schedule 80 347H or 347HH stainless steel tubular).The support conduit may provide additional creep-rupture strength andprotection for the copper and the inner conductor. For uses attemperatures greater than about 1000° C., the inner copper conductor maybe plated with a more corrosion resistant alloy (for example, Incoloy®825) to inhibit oxidation. In some embodiments, the top of thetemperature limited heater is sealed to inhibit air from contacting theinner conductor.

In some embodiments, a ferromagnetic conductor of a temperature limitedheater includes a copper core (for example, a 1.27 cm diameter coppercore) placed inside a first steel conduit (for example, a ½″ Schedule 80347H or 347HH stainless steel pipe). A second steel conduit (forexample, a 1″ Schedule 80 446 stainless steel pipe) may be drawn downover the first steel conduit assembly. The first steel conduit mayprovide strength and creep resistance while the copper core may providea high turndown ratio.

In some embodiments, a ferromagnetic conductor of a temperature limitedheater (for example, a center or inner conductor of aconductor-in-conduit temperature limited heater) includes a heavy walledconduit (for example, an extra heavy wall 410 stainless steel pipe). Theheavy walled conduit may have a diameter of about 2.5 cm. The heavywalled conduit may be drawn down over a copper rod. The copper rod mayhave a diameter of about 1.3 cm. The resulting heater may include athick ferromagnetic sheath containing the copper rod. The thickferromagnetic sheath may be the heavy walled conduit with, for example,about a 2.6 cm outside diameter after drawing. The heater may have aturndown ratio of about 8:1. The thickness of the heavy walled conduitmay be selected to inhibit deformation of the heater. A thickferromagnetic conduit may provide deformation resistance while addingminimal expense to the cost of the heater.

In another embodiment, a temperature limited heater includes asubstantially U-shaped heater with a ferromagnetic cladding over anon-ferromagnetic core (in this context, the “U” may have a curved or,alternatively, orthogonal shape). A U-shaped, or hairpin, heater mayhave insulating support mechanisms (for example, polymer or ceramicspacers) that inhibit the two legs of the hairpin from electricallyshorting to each other. In some embodiments, a hairpin heater isinstalled in a casing (for example, an environmental protection casing).The insulators may inhibit electrical shorting to the casing and mayfacilitate installation of the heater in the casing. The cross sectionof the hairpin heater may be, but is not limited to, circular,elliptical, square, or rectangular.

FIG. 115 depicts an embodiment of a temperature limited heater with ahairpin inner conductor. Inner conductor 626 may be placed in a hairpinconfiguration with two legs coupled by a substantially U-shaped sectionat or near the bottom of the heater. Current may enter inner conductor626 through one leg and exit through the other leg. Inner conductor 626may be, but is not limited to, ferritic stainless steel, carbon steel,or iron. Core 656 may be placed inside inner conductor 626. In certainembodiments, inner conductor 626 may be clad to core 656. Core 656 maybe a copper rod. The legs of the heater may be insulated from each otherand from casing 788 by spacers 790. Spacers 790 may be alumina spacers(for example, about 90% to about 99.8% alumina) or silicon nitridespacers. Weld beads or other protrusions may be placed on innerconductor 626 to maintain a location of spacers 790 on the innerconductor. In some embodiments, spacers 790 include two sections thatare fastened together around inner conductor 626. Casing 788 may be anenvironmentally protective casing made of, for example, stainless steel.

In certain embodiments, a temperature limited heater incorporatescurves, helixes, bends, or waves in a relatively straight heater toallow thermal expansion and contraction of the heater withoutoverstressing materials in the heater. When a cool heater is heated or ahot heater is cooled, the heater expands or contracts in proportion tothe change in temperature and the coefficient of thermal expansion ofmaterials in the heater. For long straight heaters that undergo widevariations in temperature during use and are fixed at more than onepoint in the wellbore (for example, due to mechanical deformation of thewellbore), the expansion or contraction may cause the heater to bend,kink and/or pull apart. Use of an “S” bend or other curves, helixes,bends, or waves in the heater at intervals in the heated length mayprovide a spring effect and allow the heater to expand or contract moregently so that the heater does not bend, kink, or pull apart.

A 310 stainless steel heater subjected to about 500° C. temperaturechange may shrink/grow approximately 0.85% of the length of the heaterwith this temperature change. Thus, a length of about 3 m of a heaterwould contract about 2.6 cm when it cools through 500° C. If a longheater were affixed at about 3 m intervals, such a change in lengthcould stretch and, possibly, break the heater. FIG. 116 depicts anembodiment of an “S” bend in a heater. The additional material in the“S” bend may allow for thermal contraction or expansion of heater 534without damage to the heater.

In some embodiments, a temperature limited heater includes a sandwichconstruction with both current supply and current return paths separatedby an insulator. The sandwich heater may include two outer layers ofconductor, two inner layers of ferromagnetic material, and a layer ofinsulator between the ferromagnetic layers. The cross-sectionaldimensions of the heater may be optimized for mechanical flexibility andspoolability. The sandwich heater may be formed as a bimetallic stripthat is bent back upon itself. The sandwich heater may be inserted in acasing, such as an environmental protection casing. The sandwich heatermay be separated from the casing with an electrical insulator.

A heater may include a section that passes through an overburden. Insome embodiments, the portion of the heater in the overburden does notneed to supply as much heat as a portion of the heater adjacent tohydrocarbon layers that are to be subjected to in situ conversion. Incertain embodiments, a substantially non-heating section of a heater haslimited or no heat output. A substantially non-heating section of aheater may be located adjacent to layers of the formation (for example,rock layers, non-hydrocarbon layers, or lean layers) that remainadvantageously unheated. A substantially non-heating section of a heatermay include a copper or aluminum conductor instead of a ferromagneticconductor. In some embodiments, a substantially non-heating section of aheater includes a copper or copper alloy inner conductor. Asubstantially non-heating section may also include a copper outerconductor clad with a corrosion resistant alloy. In some embodiments, anoverburden section includes a relatively thick ferromagnetic portion toinhibit crushing.

In certain embodiments, a temperature limited heater provides some heatto the overburden portion of a heater well and/or production well. Heatsupplied to the overburden portion may inhibit formation fluids (forexample, water and hydrocarbons) from refluxing or condensing in thewellbore. Refluxing fluids may use a large portion of heat energysupplied to a target section of the wellbore, thus limiting heattransfer from the wellbore to the target section.

A temperature limited heater may be constructed in sections that arecoupled (welded). The sections may be 10 m long or longer. Constructionmaterials for each section are chosen to provide a selected heat outputfor different parts of the formation. For example, an oil shaleformation may contain layers with highly variable richnesses. Providingselected amounts of heat to individual layers, or multiple layers withsimilar richnesses, improves heating efficiency of the formation and/orinhibits collapse of the wellbore. A splice section may be formedbetween the sections, for example, by welding the inner conductors,filling the splice section with an insulator, and then welding the outerconductor. Alternatively, the heater is formed from larger diametertubulars and drawn down to a desired length and diameter. A boronnitride, silicon nitride, magnesium oxide, or other type of insulationlayer may be added by a weld-fill-draw method (starting from metalstrip) or a fill-draw method (starting from tubulars) well known in theindustry in the manufacture of mineral insulated heater cables. Theassembly and filling can be done in a vertical or a horizontalorientation. The final heater assembly may be spooled onto a largediameter spool (for example, 1 m, 2 m, 3 m, or more in diameter) andtransported to a site of the formation for subsurface deployment.Alternatively, the heater may be assembled on site in sections as theheater is lowered vertically into a wellbore.

The temperature limited heater may be a single-phase heater or athree-phase heater. In a three-phase heater embodiment, the temperaturelimited heater has a delta or a wye configuration. Each of the threeferromagnetic conductors in the three-phase heater may be inside aseparate sheath. A connection between conductors may be made at thebottom of the heater inside a splice section. The three conductors mayremain insulated from the sheath inside the splice section.

FIG. 117 depicts an embodiment of a three-phase temperature limitedheater with ferromagnetic inner conductors. Each leg 792 has innerconductor 626, core 656, and jacket 636. Inner conductors 626 areferritic stainless steel or 1% carbon steel. Inner conductors 626 havecore 656. Core 656 may be copper. Each inner conductor 626 is coupled toits own jacket 636. Jacket 636 is a sheath made of a corrosion resistantmaterial (such as 304H stainless steel). Electrical insulator 628 isplaced between inner conductor 626 and jacket 636. Inner conductor 626is ferritic stainless steel or carbon steel with an outside diameter of1.14 cm and a thickness of 0.445 cm. Core 656 is a copper core with a0.25 cm diameter. Each leg 792 of the heater is coupled to terminalblock 794. Terminal block 794 is filled with insulation material 796 andhas an outer surface of stainless steel. Insulation material 796 is, insome embodiments, silicon nitride, boron nitride, magnesium oxide orother suitable electrically insulating material. Inner conductors 626 oflegs 792 are coupled (welded) in terminal block 794. Jackets 636 of legs792 are coupled (welded) to an outer surface of terminal block 794.Terminal block 794 may include two halves coupled around the coupledportions of legs 792.

In an embodiment, the heated section of a three-phase heater is about245 m long. The three-phase heater may be wye connected and operated ata current of about 150 A. The resistance of one leg of the heater mayincrease from about 1.1 ohms at room temperature to about 3.1 ohms atabout 650° C. The resistance of one leg may decrease rapidly above about720° C. to about 1.5 ohms. The voltage may increase from about 165 V atroom temperature to about 465 V at 650° C. The voltage may decreaserapidly above about 720° C. to about 225 V. The heat output per leg mayincrease from about 102 watts/meter at room temperature to about 285watts/meter at 650° C. The heat output per leg may decrease rapidlyabove about 720° C. to about 1.4 watts/meter. Other embodiments of innerconductor 626, core 656, jacket 636, and/or electrical insulator 628 maybe used in the three-phase temperature limited heater shown in FIG. 117.Any embodiment of a single-phase temperature limited heater may be usedas a leg of a three-phase temperature limited heater.

In some three-phase heater embodiments, three ferromagnetic conductorsare separated by insulation inside a common outer metal sheath. Thethree conductors may be insulated from the sheath or the threeconductors may be connected to the sheath at the bottom of the heaterassembly. In another embodiment, a single outer sheath or three outersheaths are ferromagnetic conductors and the inner conductors may benon-ferromagnetic (for example, aluminum, copper, or a highly conductivealloy). Alternatively, each of the three non-ferromagnetic conductorsare inside a separate ferromagnetic sheath, and a connection between theconductors is made at the bottom of the heater inside a splice section.The three conductors may remain insulated from the sheath inside thesplice section.

FIG. 118 depicts an embodiment of a three-phase temperature limitedheater with ferromagnetic inner conductors in a common jacket. Innerconductors 626 surround cores 656. Inner conductors 626 are placed inelectrical insulator 628. Inner conductors 626 and electrical insulator628 are placed in a single jacket 636. Jacket 636 is a sheath made ofcorrosion resistant material such as stainless steel. Jacket 636 has anoutside diameter of between 2.5 cm and 5 cm (for example, 3.1 cm, 3.5cm, or 3.8 cm). Inner conductors 626 are coupled at or near the bottomof the heater at termination 746. Termination 746 is a weldedtermination of inner conductors 626. Inner conductors 626 may be coupledin a wye configuration.

In some embodiments, the three-phase heater includes three legs that arelocated in separate wellbores. The legs may be coupled in a commoncontacting section (for example, a central wellbore, a connectingwellbore, or a solution filled contacting section). FIG. 119 depicts anembodiment of temperature limited heaters coupled in a three-phaseconfiguration. Each leg 798, 800, 802 may be located in separateopenings 378 in hydrocarbon layer 380. Each leg 798, 800, 802 mayinclude heating element 804. Each leg 798, 800, 802 may be coupled tosingle contacting element 806 in one opening 378. Contacting element 806may electrically couple legs 798, 800, 802 together in a three-phaseconfiguration. Contacting element 806 may be located in, for example, acentral opening in the formation. Contacting element 806 may be locatedin a portion of opening 378 below hydrocarbon layer 380 (for example, inthe underburden). In certain embodiments, magnetic tracking of amagnetic element located in a central opening (for example, opening 378with leg 800) is used to guide the formation of the outer openings (forexample, openings 378 with legs 798 and 802) so that the outer openingsintersect the central opening. The central opening may be formed firstusing standard wellbore drilling methods. Contacting element 806 mayinclude funnels, guides, or catchers for allowing each leg to beinserted into the contacting element.

In certain embodiments, two legs in separate wellbores intercept in asingle contacting section. FIG. 120 depicts an embodiment of twotemperature limited heaters coupled in a single contacting section. Legs798 and 800 include one or more heating elements 804. Heating elements804 may include one or more electrical conductors. In certainembodiments, legs 798 and 800 are electrically coupled in a single-phaseconfiguration with one leg positively biased versus the other leg sothat current flows downhole through one leg and returns through theother leg.

Heating elements 804 in legs 798 and 800 may be temperature limitedheaters. In certain embodiments, heating elements 804 are solid rodheaters. For example, heating elements 804 may be rods made of a singleferromagnetic conductor element or composite conductors that includeferromagnetic material. During initial heating when water is present inthe formation being heated, heating elements 804 may leak current intohydrocarbon layer 380. The current leaked into hydrocarbon layer 380 mayresistively heat the hydrocarbon layer.

In some embodiments (for example, in oil shale formations), heatingelements 804 do not need support members. Heating elements 804 may bepartially or slightly bent, curved, made into an S-shape, or made into ahelical shape to allow for expansion and/or contraction of the heatingelements. In certain embodiments, solid rod heating elements 804 areplaced in small diameter wellbores (for example, about 3¾″ (about 9.5cm) diameter wellbores). Small diameter wellbores may be less expensiveto drill or form than larger diameter wellbores, and there will be lesscuttings to dispose of.

In certain embodiments, portions of legs 798 and 800 in overburden 382have insulation (for example, polymer insulation) to inhibit heating theoverburden. Heating elements 804 may be substantially vertical andsubstantially parallel to each other in hydrocarbon layer 380. At ornear the bottom of hydrocarbon layer 380, leg 798 may be directionallydrilled towards leg 800 to intercept leg 800 in contacting section 808.Directional drilling may be done by, for example, Vector Magnetics LLC(Ithaca, N.Y., U.S.A.). The depth of contacting section 808 depends onthe length of bend in leg 798 needed to intercept leg 800. For example,for a 40 ft (about 12 m) spacing between vertical portions of legs 798and 800, about 200 ft (about 61 m) is needed to allow the bend of leg798 to intercept leg 800.

FIG. 121 depicts an embodiment for coupling legs 798 and 800 incontacting section 808. Heating elements 804 are coupled to contactingelements 806 at or near junction of contacting section 808 andhydrocarbon layer 380. Contacting elements 806 may be copper or anothersuitable electrical conductor. In certain embodiments, contactingelement 806 in leg 800 is a liner with opening 810. Contacting element806 from leg 798 passes through opening 810. Contactor 812 is coupled tothe end of contacting element 806 from leg 798. Contactor 812 provideselectrical coupling between contacting elements in legs 798 and 800.

FIG. 122 depicts an embodiment for coupling legs 798 and 800 incontacting section 808 with contact solution 814 in the contactingsection. Contact solution 814 is placed in portions of leg 798 and/orportions of leg 800 with contacting elements 806. Contact solution 814promotes electrical contact between contacting elements 806. Contactsolution 814 may be graphite based cement or another high electricalconductivity cement or solution (for example, brine or other ionicsolutions).

In some embodiments, electrical contact is made between contactingelements 806 using only contact solution 814. FIG. 123 depicts anembodiment for coupling legs 798 and 800 in contacting section 808without contactor 812. Contacting elements 806 may or may not touch incontacting section 808. Electrical contact between contacting elements806 in contacting section 808 is made using contact solution 814.

In certain embodiments, contacting elements 806 include one or more finsor projections. The fins or projections may increase an electricalcontact area of contacting elements 806. In some embodiments, legs 798and 800 (for example, electrical conductors in heating elements 804) areelectrically coupled but do not physically contact each other. This typeof electrical coupling may be accomplished with, for example, contactsolution 814.

FIG. 124 depicts an embodiment of three heaters coupled in a three-phaseconfiguration. Conductor “legs” 798, 800, 802 are coupled to three-phasetransformer 816. Transformer 816 may be an isolated three-phasetransformer. In certain embodiments, transformer 816 providesthree-phase output in a wye configuration, as shown in FIG. 124. Inputto transformer 816 may be made in any input configuration (such as thedelta configuration shown in FIG. 124). Legs 798, 800, 802 each includelead-in conductors 692 in the overburden of the formation coupled toheating elements 804 in hydrocarbon layer 380. Lead-in conductors 692include copper with an insulation layer. For example, lead-in conductors692 may be a 4-0 copper cables with TEFLON® insulation, a copper rodwith polyurethane insulation, or other metal conductors such as barecopper or aluminum. In certain embodiments, lead-in conductors 692 arelocated in an overburden portion of the formation. The overburdenportion may include overburden casings 680. Heating elements 804 may betemperature limited heater heating elements. In an embodiment, heatingelements 804 are 410 stainless steel rods (for example, 3.1 cm diameter410 stainless steel rods). In some embodiments, heating elements 804 arecomposite temperature limited heater heating elements (for example, 347stainless steel, 410 stainless steel, copper composite heating elements;347 stainless steel, iron, copper composite heating elements; or 410stainless steel and copper composite heating elements). In certainembodiments, heating elements 804 have a length of at least about 10 mto about 2000 m, about 20 m to about 400 m, or about 30 m to about 300m.

In certain embodiments, heating elements 804 are exposed to hydrocarbonlayer 380 and fluids from the hydrocarbon layer. Thus, heating elements804 are “bare metal” or “exposed metal” heating elements. Heatingelements 804 may be made from a material that has an acceptablesulfidation rate at high temperatures used for pyrolyzing hydrocarbons.In certain embodiments, heating elements 804 are made from material thathas a sulfidation rate that decreases with increasing temperature overat least a certain temperature range (for example, 530° C. to 650° C.),such as 410 stainless steel. Using such materials reduces corrosionproblems due to sulfur-containing gases (such as H₂S) from theformation. Heating elements 804 may also be substantially inert togalvanic corrosion.

In some embodiments, heating elements 804 have a thin electricallyinsulating layer such as aluminum oxide or thermal spray coated aluminumoxide. In some embodiments, the thin electrically insulating layer is aceramic composition such as an enamel coating. Enamel coatings include,but are not limited to, high temperature porcelain enamels. Hightemperature porcelain enamels may include silicon dioxide, boron oxide,alumina, and alkaline earth oxides (CaO or MgO), and minor amounts ofalkali oxides (Na₂O, K₂O, LiO). The enamel coating may be applied as afinely ground slurry by dipping the heating element into the slurry orspray coating the heating element with the slurry. The coated heatingelement is then heated in a furnace until the glass transitiontemperature is reached so that the slurry spreads over the surface ofthe heating element and makes the porcelain enamel coating. Theporcelain enamel coating contracts when cooled below the glasstransition temperature so that the coating is in compression. Thus, whenthe coating is heated during operation of the heater, the coating isable to expand with the heater without cracking.

The thin electrically insulating layer has low thermal impedanceallowing heat transfer from the heating element to the formation whileinhibiting current leakage between heating elements in adjacent openingsand/or current leakage into the formation. In certain embodiments, thethin electrically insulating layer is stable at temperatures above atleast 350° C., above 500° C., or above 800° C. In certain embodiments,the thin electrically insulating layer has an emissivity of at least0.7, at least 0.8, or at least 0.9. Using the thin electricallyinsulating layer may allow for long heater lengths in the formation withlow current leakage.

Heating elements 804 may be coupled to contacting elements 806 at ornear the underburden of the formation. Contacting elements 806 arecopper or aluminum rods or other highly conductive materials. In certainembodiments, transition sections 818 are located between lead-inconductors 692 and heating elements 804, and/or between heating elements804 and contacting elements 806. Transition sections 818 may be made ofa conductive material that is corrosion resistant such as 347 stainlesssteel over a copper core. In certain embodiments, transition sections818 are made of materials that electrically couple lead-in conductors692 and heating elements 804 while providing little or no heat output.Thus, transition sections 818 help to inhibit overheating of conductorsand insulation used in lead-in conductors 692 by spacing the lead-inconductors from heating elements 804. Transition section 818 may have alength of between about 3 m and about 9 m (for example, about 6 m).

Contacting elements 806 are coupled to contactor 812 in contactingsection 808 to electrically couple legs 798, 800, 802 to each other. Insome embodiments, contact solution 814 (for example, conductive cement)is placed in contacting section 808 to electrically couple contactingelements 806 in the contacting section. In certain embodiments, legs798, 800, 802 are substantially parallel in hydrocarbon layer 380 andleg 798 continues substantially vertically into contacting section 808.The other two legs 800, 802 are directed (for example, by directionallydrilling the wellbores for the legs) to intercept leg 798 in contactingsection 808.

Each leg 798, 800, 802 may be one leg of a three-phase heater embodimentso that the legs are substantially electrically isolated from otherheaters in the formation and are substantially electrically isolatedfrom the formation. Legs 798, 800, 802 may be arranged in a triangularpattern so that the three legs form a triangular shaped three-phaseheater. In an embodiment, legs 798, 800, 802 are arranged in atriangular pattern with 12 m spacing between the legs (each side of thetriangle has a length of 12 m).

In certain embodiments, the thin electrically insulating layer allowsfor relatively long, substantially horizontal heater leg lengths in thehydrocarbon layer with a substantially u-shaped heater. FIG. 125 depictsa side-view representation of an embodiment of a substantially u-shapedthree-phase heater. First ends of legs 798, 800, 802 are coupled totransformer 816 at first location 878. In an embodiment, transformer 816is a three-phase AC transformer. Ends of legs 798, 800, 802 areelectrically coupled together with connector 886 at second location 884.Connector 886 electrically couples the ends of legs 798, 800, 802 sothat the legs can be operated in a three-phase configuration. In certainembodiments, legs 798, 800, 802 are coupled to operate in a three-phasewye configuration. In certain embodiments, legs 798, 800, 802 aresubstantially parallel in hydrocarbon layer 380. In certain embodiments,legs 798, 800, 802 are arranged in a triangular pattern in hydrocarbonlayer 380. In certain embodiments, heating elements 804 include a thinelectrically insulating material (such as a porcelain enamel coating) toinhibit current leakage from the heating elements. In certainembodiments, legs 798, 800, 802 are electrically coupled so that thelegs are substantially electrically isolated from other heaters in theformation and are substantially electrically isolated from theformation.

In certain embodiments, overburden casings (for example, overburdencasings 680, depicted in FIGS. 124 and 125) in overburden 382 includematerials that inhibit ferromagnetic effects in the casings. Inhibitingferromagnetic effects in casings 680 reduces heat losses to theoverburden. In some embodiments, casings 680 may include non-metallicmaterials such as fiberglass, polyvinylchloride (PVC), chlorinatedpolyvinylchloride (CPVC), or high-density polyethylene (HDPE). HDPEswith working temperatures in a range for use in overburden 382 includeHDPEs available from Dow Chemical Co., Inc. (Midland, Mich., U.S.A.). Anon-metallic casing may also eliminate the need for an insulatedoverburden conductor. In some embodiments, casings 680 include carbonsteel coupled on the inside diameter of a non-ferromagnetic metal (forexample, carbon steel clad with copper or aluminum) to inhibitferromagnetic effects or inductive effects in the carbon steel. Othernon-ferromagnetic metals include, but are not limited to, manganesesteels with at least 10% by weight manganese, iron aluminum alloys withat least 18% by weight aluminum, and austentitic stainless steels suchas 304 stainless steel or 316 stainless steel.

In certain embodiments, one or more non-ferromagnetic materials used incasings 680 are used in a wellhead coupled to the casings and legs 798,800, 802. Using non-ferromagnetic materials in the wellhead inhibitsundesirable heating of components in the wellhead. In some embodiments,a purge gas (for example, carbon dioxide, nitrogen or argon) isintroduced into the wellhead and/or inside of casings 680 to inhibitreflux of heated gases into the wellhead and/or the casings.

In certain embodiments, one or more of legs 798, 800, 802 are installedin the formation using coiled tubing. In certain embodiments, coiledtubing is installed in the formation, the leg is installed inside thecoiled tubing, and the coiled tubing is pulled out of the formation toleave the leg installed in the formation. The leg may be placedconcentrically inside the coiled tubing. In some embodiments, coiledtubing with the leg inside the coiled tubing is installed in theformation and the coiled tubing is removed from the formation to leavethe leg installed in the formation. The coiled tubing may extend only toa junction of hydrocarbon layer 380 and contacting section 808 or to apoint at which the leg begins to bend in the contacting section.

FIG. 126 depicts a top view representation of an embodiment of aplurality of triads of three-phase heaters in the formation. Each triad820 includes legs A, B, C (which may correspond to legs 798, 800, 802depicted in FIGS. 124 and 125) that are electrically coupled by linkage822. Each triad 820 is coupled to its own electrically isolatedthree-phase transformer so that the triads are substantiallyelectrically isolated from each other. Electrically isolating the triadsinhibits net current flow between triads.

The phases of each triad 820 may be arranged so that legs A, B, Ccorrespond between triads as shown in FIG. 126. In FIG. 126, legs A, B,C are arranged such that a phase leg (for example, leg A) in a giventriad is about two triad heights from a same phase leg (leg A) in anadjacent triad. The triad height is the distance from a vertex of thetriad to a midpoint of the line intersecting the other two vertices ofthe triad. In certain embodiments, the phases of triads 820 are arrangedto inhibit net current flow between individual triads. There may be someleakage of current within an individual triad but little net currentflows between two triads due to the substantial electrical isolation ofthe triads and, in certain embodiments, the arrangement of the triadphases.

In the early stages of heating, an exposed heating element (for example,heating element 804 depicted in FIGS. 124 and 125) may leak some currentto water or other fluids that are electrically conductive in theformation so that the formation itself is heated. After water or otherelectrically conductive fluids are removed from the wellbore (forexample, vaporized or produced), the heating elements becomeelectrically isolated from the formation. Later, when water is removedfrom the formation, the formation becomes even more electricallyresistant and heating of the formation occurs even more predominantlyvia thermally conductive and/or radiative heating. Typically, theformation (the hydrocarbon layer) has an initial electrical resistancethat averages at least 10 ohm·m. In some embodiments, the formation hasan initial electrical resistance of at least 100 ohm·m or of at least300 ohm·m.

Using the temperature limited heaters as the heating elements limits theeffect of water saturation on heater efficiency. With water in theformation and in heater wellbores, there is a tendency for electricalcurrent to flow between heater elements at the top of the hydrocarbonlayer where the voltage is highest and cause uneven heating in thehydrocarbon layer. This effect is inhibited with temperature limitedheaters because the temperature limited heaters reduce localizedoverheating in the heating elements and in the hydrocarbon layer.

In certain embodiments, production wells are placed at a location atwhich there is relatively little or zero voltage potential. Thislocation minimizes stray potentials at the production well. Placingproduction wells at such locations improves the safety of the system andreduces or inhibits undesired heating of the production wells caused byelectrical current flow in the production wells. FIG. 127 depicts a topview representation of the embodiment depicted in FIG. 126 withproduction wells 206. In certain embodiments, production wells 206 arelocated at or near center of triad 820. In certain embodiments,production wells 206 are placed at a location between triads at whichthere is relatively little or zero voltage potential (at a location atwhich voltage potentials from vertices of three triads average out torelatively little or zero voltage potential). For example, productionwell 206 may be at a location equidistant from legs A of one triad, legB of a second triad, and leg C of a third triad, as shown in FIG. 127.

FIG. 128 depicts a top view representation of an embodiment of aplurality of triads of three-phase heaters in a hexagonal pattern in theformation. FIG. 129 depicts a top view representation of an embodimentof a hexagon from FIG. 128. Hexagon 824 includes two triads of heaters.The first triad includes legs A1, B1, C1 electrically coupled togetherby linkages 822 in a three-phase configuration. The second triadincludes legs A2, B2, C2 electrically coupled together by linkages 822in a three-phase configuration. The triads are arranged so thatcorresponding legs of the triads (for example, A1 and A2, B1 and B2, C1and C2) are at opposite vertices of hexagon 824. The triads areelectrically coupled and arranged so that there is relatively little orzero voltage potential at or near the center of hexagon 824.

Production well 206 may be placed at or near the center of hexagon 824.Placing production well 206 at or near the center of hexagon 824 placesthe production well at a location that reduces or inhibits undesiredheating due to electromagnetic effects caused by electrical current flowin the legs of the triads and increases the safety of the system. Havingtwo triads in hexagon 824 provides for redundant heating aroundproduction well 206. Thus, if one triad fails or has to be turned off,production well 206 still remains at a center of one triad.

As shown in FIG. 128, hexagons 824 may be arranged in a pattern in theformation such that adjacent hexagons are offset. Using electricallyisolated transformers on adjacent hexagons may inhibit electricalpotentials in the formation so that little or no net current leaksbetween hexagons.

Triads of heaters and/or heater legs may be arranged in any shape ordesired pattern. For example, as described above, triads may includethree heaters and/or heater legs arranged in a equilateral triangularpattern. In some embodiments, triads include three heaters and/or heaterlegs arranged in other triangular shapes (for example, an isoscelestriangle or a right angle triangle). In some embodiments, heater legs inthe triad cross each other (for example, criss-cross) in the formation.In certain embodiments, triads includes three heaters and/or heater legsarranged sequentially along a straight line.

FIG. 130 depicts an embodiment with triads coupled to a horizontalconnector well. Triad 820A includes legs 798A, 800A, 802A. Triad 820Bincludes legs 798B, 800B, 802B. Legs 798A, 800A, 802A and legs 798B,800B, 802B may be arranged along a straight line on the surface of theformation. In some embodiments, legs 798A, 800A, 802A are arranged alonga straight line and offset from legs 798B, 800B, 802B, which may bearranged along a straight line. Legs 798A, 800A, 802A and legs 798B,800B, 802B include heating elements 804 located in hydrocarbon layer380. Lead-in conductors 692 couple heating elements 804 to the surfaceof the formation. Heating elements 804 are coupled to contactingelements 806 at or near the underburden of the formation. In certainembodiments, transition sections (for example, transition sections 818depicted in FIG. 124) are located between lead-in conductors 692 andheating elements 804, and/or between heating elements 804 and contactingelements 806.

Contacting elements 806 are coupled to contactor 812 in contactingsection 808 to electrically couple legs 798A, 800A, 802A to each otherto form triad 820A and electrically couple legs 798B, 800B, 802B to eachother to form triad 820B. In certain embodiments, contactor 812 is aground conductor so that triad 820A and/or triad 820B may be coupled inthree-phase wye configurations. In certain embodiments, triad 820A andtriad 820B are electrically isolated from each other. In someembodiments, triad 820A and triad 820B are electrically coupled to eachother (for example, electrically coupled in series or parallel).

In certain embodiments, contactor 812 is a substantially horizontalcontactor located in contacting section 808. Contactor 812 may be acasing or a solid rod placed in a wellbore drilled substantiallyhorizontally in contacting section 808. Legs 798A, 800A, 802A and legs798B, 800B, 802B may be electrically coupled to contactor 812 by anymethod described herein or any method known in the art. For example,containers with thermite powder are coupled to contactor 812 (forexample, by welding or brazing the containers to the contactor), legs798A, 800A, 802A and legs 798B, 800B, 802B are placed inside thecontainers, and the thermite powder is activated to electrically couplethe legs to the contactor. The containers may be coupled to contactor812 by, for example, placing the containers in holes or recesses incontactor 812 or coupled to the outside of the contactor and thenbrazing or welding the containers to the contactor.

FIG. 131 depicts cumulative gas production and cumulative oil productionversus time (years) found from a STARS simulation (Computer ModellingGroup, LTD., Calgary, Alberta, Canada) using the temperature limitedheaters and heater pattern depicted in FIGS. 124 and 126. Curve 826depicts cumulative oil production (m³) for an initial water saturationof 15%. Curve 828 depicts cumulative gas production (m³) for the initialwater saturation of 15%. Curve 830 depicts cumulative oil production(m³) for an initial water saturation of 85%. Curve 832 depictscumulative gas production (m³) for the initial water saturation of 85%.As shown by the small differences between curves 826 and 830 forcumulative oil production and curves 828 and 832 for cumulative gasproduction, the initial water saturation does not substantially alterheating of the formation. As a result, the overall production ofhydrocarbons from the formation is also not substantially changed by theinitial water saturation. Using the temperature limited heaters inhibitsvariances in heating of the formation that otherwise may be caused bythe differences in the initial water saturation.

As shown in FIG. 124, contacting elements 806 of legs 798, 800, 802 maybe coupled using contactor 812 and/or contact solution 814. In certainembodiments, contacting elements 806 of legs 798, 800, 802 arephysically coupled, for example, through soldering, welding, or othertechniques. FIGS. 132 and 133 depict embodiments for coupling contactingelements 806 of legs 798, 800, 802. Legs 800, 802 may enter the wellboreof leg 798 from any direction desired. In one embodiment, legs 800, 802enter the wellbore of leg 798 from approximately the same side of thewellbore, as shown in FIG. 132. In an alternative embodiment, legs 800,802 enter the wellbore of leg 798 from approximately opposite sides ofthe wellbore, as shown in FIG. 133.

Container 834 is coupled to contacting element 806 of leg 798. Container834 may be soldered, welded, or otherwise electrically coupled tocontacting element 806. Container 834 is a metal can or other containerwith at least one opening for receiving one or more contacting elements806. In an embodiment, container 834 is a can that has an opening forreceiving contacting elements 806 from legs 800, 802, as shown in FIG.132. In certain embodiments, wellbores for legs 800, 802 are drilledparallel to the wellbore for leg 798 through the hydrocarbon layer thatis to be heated and directionally drilled below the hydrocarbon layer tointercept wellbore for leg 798 at an angle between about 10° and about20° from vertical. Wellbores may be directionally drilled using knowntechniques such as techniques used by Vector Magnetics, Inc.

In some embodiments, contacting elements 806 contact the bottom ofcontainer 834. Contacting elements 806 may contact the bottom ofcontainer 834 and/or each other to promote electrical connection betweenthe contacting elements and/or the container. In certain embodiments,end portions of contacting elements 806 are annealed to a “dead soft”condition to facilitate entry into container 834. In some embodiments,rubber or other softening material is attached to end portions ofcontacting elements 806 to facilitate entry into container 834. In someembodiments, contacting elements 806 include reticulated sections, suchas knuckle-joints or limited rotation knuckle-joints, to facilitateentry into container 834.

In certain embodiments, an electrical coupling material is placed incontainer 834. The electrical coupling material may line the walls ofcontainer 834 or fill up a portion of the container. In certainembodiments, the electrical coupling material lines an upper portion,such as the funnel-shaped portion shown in FIG. 134, of container 834.The electrical coupling material includes one or more materials thatwhen activated (for example, heated, ignited, exploded, combined, mixed,and/or reacted) form a material that electrically couples one or moreelements to each other. In an embodiment, the coupling materialelectrically couples contacting elements 806 in container 834. In someembodiments, the coupling material metallically bonds to contactingelements 806 so that the contacting elements are metallically bonded toeach other. In some embodiments, container 834 is initially filled witha high viscosity water-based polymer fluid to inhibit drill cuttings orother materials from entering the container prior to using the couplingmaterial to couple the contacting elements. The polymer fluid may be,but is not limited to, a cross-linked XC polymer (available from BaroidIndustrial Drilling Products (Houston, Tex., U.S.A.), a frac gel, or across-linked polyacrylamide gel.

In certain embodiments, the electrical coupling material is alow-temperature solder that melts at relatively low temperature and whencooled forms an electrical connection to exposed metal surfaces. Incertain embodiments, the electrical coupling material is a solder thatmelts at a temperature below the boiling point of water at the depth ofcontainer 834. In one embodiment, the electrical coupling material is a58% by weight bismuth and 42% by weight tin eutectic alloy. Otherexamples of such solders include, but are not limited to, a 54% byweight bismuth, 16% by weight tin, 30% by weight indium alloy, and a 48%by weight tin, 52% by weight indium alloy. Such low-temperature solderswill displace water upon melting so that the water moves to the top ofcontainer 834. Water at the top of container 834 may inhibit heattransfer into the container and thermally insulate the low-temperaturesolder so that the solder remains at cooler temperatures and does notmelt during heating of the formation using the heating elements.

Container 834 may be heated to activate the electrical coupling materialto facilitate the connection of contacting elements 806. In certainembodiments, container 834 is heated to melt the electrical couplingmaterial in the container. The electrical coupling material flows whenmelted and surrounds contacting elements 806 in container 834. Any waterwithin container 834 will float to the surface of the metal when themetal is melted. The electrical coupling material is allowed to cool andelectrically connects contacting elements 806 to each other. In certainembodiments, contacting elements 806 of legs 800, 802, the inside wallsof container 834, and/or the bottom of the container are initiallypre-tinned with electrical coupling material.

End portions of contacting elements 806 of legs 798, 800, 802 may haveshapes and/or features that enhance the electrical connection betweenthe contacting elements and the coupling material. The shapes and/orfeatures of contacting elements 806 may also enhance the physicalstrength of the connection between the contacting elements and thecoupling material (for example, the shape and/or features of thecontacting element may anchor the contacting element in the couplingmaterial). Shapes and/or features for end portions of contactingelements 806 include, but are not limited to, grooves, notches, holes,threads, serrated edges, openings, and hollow end portions. In certainembodiments, the shapes and/or features of the end portions ofcontacting elements 806 are initially pre-tinned with electricalcoupling material.

FIG. 134 depicts an embodiment of container 834 with an initiator formelting the coupling material. The initiator is an electrical resistanceheating element or any other element for providing heat that activatesor melts the coupling material in container 834. In certain embodiments,heating element 836 is a heating element located in the walls ofcontainer 834. In some embodiments, heating element 836 is located onthe outside of container 834. Heating element 836 may be, for example, anichrome wire, a mineral-insulated conductor, a polymer-insulatedconductor, a cable, or a tape that is inside the walls of container 834or on the outside of the container. In some embodiments, heating element836 wraps around the inside walls of the container or around the outsideof the container. Lead-in wire 838 may be coupled to a power source atthe surface of the formation. Lead-out wire 840 may be coupled to thepower source at the surface of the formation. Lead-in wire 838 and/orlead-out wire 840 may be coupled along the length of leg 798 formechanical support. Lead-in wire 838 and/or lead-out wire 840 may beremoved from the wellbore after melting the coupling material. Lead-inwire 838 and/or lead-out wire 840 may be reused in other wellbores.

In some embodiments, container 834 has a funnel-shape, as shown in FIG.134, that facilitates the entry of contacting elements 806 into thecontainer. In certain embodiments, container 834 is made of or includescopper for good electrical and thermal conductivity. A copper container834 makes good electrical contact with contacting elements (such ascontacting elements 806 shown in FIGS. 132 and 133) if the contactingelements touch the walls and/or bottom of the container.

FIG. 135 depicts an embodiment of container 834 with bulbs on contactingelements 806. Protrusions 842 may be coupled to a lower portion ofcontacting elements 806. Protrusions 844 may be coupled to the innerwall of container 834. Protrusions 842, 844 may be made of copper oranother suitable electrically conductive material. Lower portion ofcontacting element 806 of leg 802 may have a bulbous shape, as shown inFIG. 135. In certain embodiments, contacting element 806 of leg 802 isinserted into container 834. Contacting element 806 of leg 800 isinserted after insertion of contacting element 806 of leg 802. Both legsmay then be pulled upwards simultaneously. Protrusions 842 may lockcontacting elements 806 into place against protrusions 844 in container834. A friction fit is created between contacting elements 806 andprotrusions 842, 844.

Lower portions of contacting elements 806 inside container 834 mayinclude 410 stainless steel or any other heat generating electricalconductor. Portions of contacting elements 806 above the heat generatingportions of the contacting elements include copper or another highlyelectrically conductive material. Centralizers 672 may be located on theportions of contacting elements 806 above the heat generating portionsof the contacting elements. Centralizers 672 inhibit physical andelectrical contact of portions of contacting elements 806 above the heatgenerating portions of the contacting elements against walls ofcontainer 834.

When contacting elements 806 are locked into place inside container 834by protrusions 842, 844, at least some electrical current may be passbetween the contacting elements through the protrusions. As electricalcurrent is passed through the heat generating portions of contactingelements 806, heat is generated in container 834. The generated heat maymelt coupling material 846 located inside container 834. Water incontainer 834 may boil. The boiling water may convect heat to upperportions of container 834 and aid in melting of coupling material 846.Walls of container 834 may be thermally insulated to reduce heat lossesout of the container and allow the inside of the container to heat upfaster. Coupling material 846 flows down into the lower portion ofcontainer 834 as the coupling material melts. Coupling material 846fills the lower portion of container 834 until the heat generatingportions of contacting elements 806 are below the fill line of thecoupling material. Coupling material 846 then electrically couples theportions of contacting elements 806 above the heat generating portionsof the contacting elements. The resistance of contacting elements 806decreases at this point and heat is no longer generated in thecontacting elements and the coupling materials is allowed to cool.

In certain embodiments, container 834 includes insulation layer 848inside the housing of the container. Insulation layer 848 may includethermally insulating materials to inhibit heat losses from the canister.For example, insulation layer 848 may include magnesium oxide, siliconnitride, or other thermally insulating materials that withstandoperating temperatures in container 834. In certain embodiments,container 834 includes liner 850 on an inside surface of the container.Liner 850 may increase electrical conductivity inside container 834.Liner 850 may include electrically conductive materials such as copperor aluminum.

FIG. 136 depicts an alternative embodiment for container 834. Couplingmaterial in container 834 includes powder 852. Powder 852 is a chemicalmixture that produces a molten metal product from a reaction of thechemical mixture. In an embodiment, powder 852 is thermite powder.Powder 852 lines the walls of container 834 and/or is placed in thecontainer. Igniter 854 is placed in powder 852. Igniter 854 may be, forexample, a magnesium ribbon that when activated ignites the reaction ofpowder 852. When powder 852 reacts, a molten metal produced by thereaction flows and surrounds contacting elements 806 placed in container834. When the molten metal cools, the cooled metal electrically connectscontacting elements 806. In some embodiments, powder 852 is used incombination with another coupling material, such as a low-temperaturesolder, to couple contacting elements 806. The heat of reaction ofpowder 852 may be used to melt the low temperature-solder.

In certain embodiments, an explosive element is placed in container 834,depicted in FIG. 132 or FIG. 136. The explosive element may be, forexample, a shaped charge explosive or other controlled explosiveelement. The explosive element may be exploded to crimp contactingelements 806 and/or container 834 together so that the contactingelements and the container are electrically connected. In someembodiments, an explosive element is used in combination with anelectrical coupling material such as low-temperature solder or thermitepowder to electrically connect contacting elements 806.

FIG. 137 depicts an alternative embodiment for coupling contactingelements 806 of legs 798, 800, 802. Container 834A is coupled tocontacting element 806 of leg 800. Container 834B is coupled tocontacting element 806 of leg 802. Container 834B is sized and shaped tobe placed inside container 834A. Container 834C is coupled to contactingelement 806 of leg 798. Container 834C is sized and shaped to be placedinside container 834B. In some embodiments, contacting element 806 ofleg 798 is placed in container 834B without a container attached to thecontacting element. One or more of containers 834A, 834B, 834C may befilled with a coupling material that is activated to facilitate anelectrical connection between contacting elements 806 as describedabove.

FIG. 138 depicts a side view representation of an embodiment forcoupling contacting elements using temperature limited heating elements.Contacting elements 806 of legs 798, 800, 802 may have insulation 856 onportions of the contacting elements above container 834. Container 834may be shaped and/or have guides at the top to guide the insertion ofcontacting elements 806 into the container. Coupling material 846 may belocated inside container 834 at or near a top of the container. Couplingmaterial 846 may be, for example, a solder material. In someembodiments, inside walls of container 834 are pre-coated with couplingmaterial or another electrically conductive material such as copper oraluminum. Centralizers 672 may be coupled to contacting elements 806 tomaintain a spacing of the contacting elements in container 834.Container 834 may be tapered at the bottom to push lower portions ofcontacting elements 806 together for at least some electrical contactbetween the lower portions of the contacting elements.

Heating elements 858 may be coupled to portions of contacting elements806 inside container 834. Heating elements 858 may include ferromagneticmaterials such as iron or stainless steel. In an embodiment, heatingelements 858 are iron cylinders clad onto contacting elements 806.Heating elements 858 may be designed with dimensions and materials thatwill produce a desired amount of heat in container 834. In certainembodiments, walls of container 834 are thermally insulated withinsulation layer 848, as shown in FIG. 138 to inhibit heat loss from thecontainer. Heating elements 858 may be spaced so that contactingelements 806 have one or more portions of exposed material insidecontainer 834. The exposed portions include exposed copper or anothersuitable highly electrically conductive material. The exposed portionsallow for better electrical contact between contacting elements 806 andcoupling material 846 after the coupling material has been melted, fillscontainer 834, and is allowed to cool.

In certain embodiments, heating elements 858 operate as temperaturelimited heaters when a time-varying current is applied to the heatingelements. For example, a 400 Hz, AC current may be applied to heatingelements 858. Application of the time-varying current to contactingelements 806 causes heating elements 858 to generate heat and meltcoupling material 846. Heating elements 858 may operate as temperaturelimited heating elements with a self-limiting temperature selected sothat coupling material 846 is not overheated. As coupling material 846fills container 834, the coupling material makes electrical contactbetween portions of exposed material on contacting elements 806 andelectrical current begins to flow through the exposed material portionsrather than heating elements 858. Thus, the electrical resistancebetween the contacting elements decreases. As this occurs, temperaturesinside container 834 begin to decrease and coupling material 846 isallowed to cool to create an electrical contacting section betweencontacting elements 806. In certain embodiments, electrical power tocontacting elements 806 and heating elements 858 is turned off when theelectrical resistance in the system falls below a selected resistance.The selected resistance may indicate that the coupling material hassufficiently electrically connected the contacting elements. In someembodiments, electrical power is supplied to contacting elements 806 andheating elements 858 for a selected amount of time that is determined toprovide enough heat to melt the mass of coupling material 846 providedin container 834.

FIG. 139 depicts a side view representation of an alternative embodimentfor coupling contacting elements using temperature limited heatingelements. Contacting element 806 of leg 798 may be coupled to container834 by welding, brazing, or another suitable method. Lower portion ofcontacting element 806 of leg 802 may have a bulbous shape. Contactingelement 806 of leg 802 is inserted into container 834. Contactingelement 806 of leg 800 is inserted after insertion of contacting element806 of leg 802. Both legs may then be pulled upwards simultaneously.Protrusions 844 may lock contacting elements 806 into place and afriction fit may be created between the contacting elements 806.Centralizers 672 may inhibit electrical contact between upper portionsof contacting elements 806.

Time-varying electrical current may be applied to contacting elements806 so that heating elements 858 generate heat. The generated heat maymelt coupling material 846 located in container 834 and be allowed tocool, as described for the embodiment depicted in FIG. 138. Aftercooling of coupling material 846, contacting elements 806 of legs 800,802, shown in FIG. 139, are electrically coupled in container 834 withthe coupling material. In some embodiments, lower portions of contactingelements 806 have protrusions or openings that anchor the contactingelements in cooled coupling material. Exposed portions of the contactingelements provide a low electrical resistance path between the contactingelements and the coupling material.

FIG. 140 depicts a side view representation of another embodiment forcoupling contacting elements using temperature limited heating elements.Contacting element 806 of leg 798 may be coupled to container 834 bywelding, brazing, or another suitable method. Lower portion ofcontacting element 806 of leg 802 may have a bulbous shape. Contactingelement 806 of leg 802 is inserted into container 834. Contactingelement 806 of leg 800 is inserted after insertion of contacting element806 of leg 802. Both legs may then be pulled upwards simultaneously.Protrusions 844 may lock contacting elements 806 into place and afriction fit may be created between the contacting elements 806.Centralizers 672 may inhibit electrical contact between upper portionsof contacting elements 806.

End portions 806B of contacting elements 806 may be made of aferromagnetic material such as 410 stainless steel. Portions 806A mayinclude non-ferromagnetic electrically conductive material such ascopper or aluminum. Time-varying electrical current may be applied tocontacting elements 806 so that end portions 806B generate heat due tothe resistance of the end portions. The generated heat may melt couplingmaterial 846 located in container 834 and be allowed to cool, asdescribed for the embodiment depicted in FIG. 138. After cooling ofcoupling material 846, contacting elements 806 of legs 800, 802, shownin FIG. 139, are electrically coupled in container 834 with the couplingmaterial. Portions 806A may be below the fill line of coupling material846 so that these portions of the contacting elements provide a lowelectrical resistance path between the contacting elements and thecoupling material.

FIG. 141 depicts a side view representation of an alternative embodimentfor coupling contacting elements of three legs of a heater. FIG. 142depicts a top view representation of the alternative embodiment forcoupling contacting elements of three legs of the heater depicted inFIG. 141. Container 834 may include inner container 860 and outercontainer 862. Inner container 860 may be made of copper or anothermalleable, electrically conductive metal such as aluminum. Outercontainer 862 may be made of a rigid material such as stainless steel.Outer container 862 protects inner container 860 and its contents fromenvironmental conditions outside of container 834.

Inner container 860 may be substantially solid with two openings 864 and866. Inner container 860 is coupled to contacting element 806 of leg798. For example, inner container 860 may be welded or brazed tocontacting element 806 of leg 798. Openings 864, 866 are shaped to allowcontacting elements 806 of legs 800, 802 to enter the openings as shownin FIG. 141. Funnels or other guiding mechanisms may be coupled to theentrances to openings 864, 866 to guide contacting elements 806 of legs800, 802 into the openings. Contacting elements 806 of legs 798, 800,802 may be made of the same material as inner container 860.

Explosive elements 868 may be coupled to the outer wall of innercontainer 860. In certain embodiments, explosive elements 868 areelongated explosive strips that extend along the outer wall of innercontainer 860. Explosive elements 868 may be arranged along the outerwall of inner container 860 so that the explosive elements are alignedat or near the centers of contacting elements 806, as shown in FIG. 142.Explosive elements 868 are arranged in this configuration so that energyfrom the explosion of the explosive elements causes contacting elements806 to be pushed towards the center of inner container 860.

Explosive elements 868 may be coupled to battery 870 and timer 872.Battery 870 may provide power to explosive elements 868 to initiate theexplosion. Timer 872 may be used to control the time for ignitingexplosive elements 868. Battery 870 and timer 872 may be coupled totriggers 874. Triggers 874 may be located in openings 864, 866.Contacting elements 806 may set off triggers 874 as the contactingelements are placed into openings 864, 866. When both triggers 874 inopenings 864, 866 are triggered, timer 872 may initiate a countdownbefore igniting explosive elements 868. Thus, explosive elements 868 arecontrolled to explode only after contacting elements 806 are placedsufficiently into openings 864, 866 so that electrical contact may bemade between the contacting elements and inner container 860 after theexplosions. Explosion of explosive elements 868 crimps contactingelements 806 and inner container 860 together to make electrical contactbetween the contacting elements and the inner container. In certainembodiments, explosive elements 868 fire from the bottom towards the topof inner container 860. Explosive elements 868 may be designed with alength and explosive power (band width) that gives an optimum electricalcontact between contacting elements 806 and inner container 860.

In some embodiments, triggers 874, battery 870, and timer 872 may beused to ignite a powder (for example, copper thermite powder) inside acontainer (for example, container 834 or inner container 860). Battery870 may charge a magnesium ribbon or other ignition device in the powderto initiate reaction of the powder to produce a molten metal product.The molten metal product may flow and then cool to electrically contactthe contacting elements.

In certain embodiments, electrical connection is made between contactingelements 806 through mechanical means. FIG. 143 depicts an embodiment ofcontacting element 806 with a brush contactor. Brush contactor 876 iscoupled to a lower portion of contacting element 806. Brush contactor876 may be made of a malleable, electrically conductive material such ascopper or aluminum. Brush contactor 876 may be a webbing of materialthat is compressible and/or flexible. Centralizer 672 may be located ator near the bottom of contacting element 806.

FIG. 144 depicts an embodiment for coupling contacting elements 806 withbrush contactors 876. Brush contactors 876 are coupled to eachcontacting element 806 of legs 798, 800, 802. Brush contactors 876compress against each other and interlace to electrically couplecontacting elements 806 of legs 798, 800, 802. Centralizers 672 maintainspacing between contacting elements 806 of legs 798, 800, 802 so thatinterference and/or clearance issues between the contacting elements areinhibited.

In certain embodiments, contacting elements 806 (depicted in FIGS.132-144) are coupled in a zone of the formation that is cooler than thelayer of the formation to be heated (for example, in the underburden ofthe formation). Contacting elements 806 are coupled in a cooler zone toinhibit melting of the coupling material and/or degradation of theelectrical connection between the elements during heating of thehydrocarbon layer above the cooler zone. In certain embodiments,contacting elements 806 are coupled in a zone that is at least about 3m, at least about 6 m, or at least about 9 m below the layer of theformation to be heated. In some embodiments, the zone has a standingwater level that is above a depth of containers 834.

In certain embodiments, exposed metal heating elements are used insubstantially horizontal sections of u-shaped wellbores. Substantiallyu-shaped wellbores may be used in tar sands formations, oil shaleformation, or other formations with relatively thin hydrocarbon layers.Tar sands or thin oil shale formations may have thin shallow layers thatare more easily and uniformly heated using heaters placed insubstantially u-shaped wellbores. Substantially u-shaped wellbores mayalso be used to process formations with thick hydrocarbon layers informations. In some embodiments, substantially u-shaped wellbores areused to access rich layers in a thick hydrocarbon formation.

Heaters in substantially unshaped wellbores may have long lengthscompared to heaters in vertical wellbores because horizontal heatingsections do not have problems with creep or hanging stress encounteredwith vertical heating elements. Substantially unshaped wellbores maymake use of natural seals in the formation and/or the limited thicknessof the hydrocarbon layer. For example, the wellbores may be placed aboveor below natural seals in the formation without punching large numbersof holes in the natural seals, as would be needed with verticallyoriented wellbores. Using substantially u-shaped wellbores instead ofvertical wellbores may also reduce the number of wells needed to treat asurface footprint of the formation. Using less wells reduces capitalcosts for equipment and reduces the environmental impact of treating theformation by reducing the amount of wellbores on the surface and theamount of equipment on the surface. Substantially u-shaped wellbores mayalso utilize a lower ratio of overburden section to heated section thanvertical wellbores.

Substantially u-shaped wellbores may allow for flexible placement ofopening of the wellbores on the surface. Openings to the wellbores maybe placed according to the surface topology of the formation. In certainembodiments, the openings of wellbores are placed at geographicallyaccessible locations such as topological highs (for examples, hills).For example, the wellbore may have a first opening on a first topologichigh and a second opening on a second topologic high and the wellborecrosses beneath a topologic low (for example, a valley with alluvialfill) between the first and second topologic highs. This placement ofthe openings may avoid placing openings or equipment in topologic lowsor other inaccessible locations. In addition, the water level may not beartesian in topologically high areas. Wellbores may be drilled so thatthe openings are not located near environmentally sensitive areas suchas, but not limited to, streams, nesting areas, or animal refuges.

FIG. 145 depicts a side-view representation of an embodiment of a heaterwith an exposed metal heating element placed in a substantially u-shapedwellbore. Heaters 880A, 880B, 880C have first end portions at firstlocation 878 on surface 550 of the formation and second end portions atsecond location 884 on the surface. Heaters 880A, 880B, 880C havesections 888 in overburden 382. Sections 888 are configured to providelittle or no heat output. In certain embodiments, sections 888 includean insulated electrical conductor such as insulated copper. Sections 888are coupled to heating elements 804.

In certain embodiments, portions of heating elements 804 aresubstantially parallel in hydrocarbon layer 380. In certain embodiments,heating elements 804 are exposed metal heating elements. In certainembodiments, heating elements 804 are exposed metal temperature limitedheating elements. Heating elements 804 may include ferromagneticmaterials such as 9% by weight to 13% by weight chromium stainless steellike 410 stainless steel, chromium stainless steels such as T/P91 orT/P92, 409 stainless steel, VM12 (Vallourec and Mannesmann Tubes,France) or iron-cobalt alloys for use as temperature limited heaters. Insome embodiments, heating elements 804 are composite temperature limitedheating elements such as 410 stainless steel and copper compositeheating elements or 347H, iron, copper composite heating elements.Heating elements 804 may have lengths of at least about 100 m, at leastabout 500 m, or at least about 1000 m, up to lengths of about 6000 m.

Heating elements 804 may be solid rods or tubulars. In certainembodiments, solid rod heating elements have diameters several times theskin depth at the Curie temperature of the ferromagnetic material.Typically, the solid rod heating elements may have diameters of 1.91 cmor larger (for example, 2.5 cm, 3.2 cm, 3.81 cm, or 5.1 cm). In certainembodiments, tubular heating elements have wall thicknesses of at leasttwice the skin depth at the Curie temperature of the ferromagneticmaterial. Typically, the tubular heating elements have outside diametersof between about 2.5 cm and about 15.2 cm and wall thickness in rangebetween about 0.13 cm and about 1.01 cm.

In certain embodiments, tubular heating elements 804 allow fluids to beconvected through the tubular heating elements. Fluid flowing throughthe tubular heating elements may be used to preheat the tubular heatingelements, to initially heat the formation, and/or to recover heat fromthe formation after heating is completed for the in situ conversionprocess. Fluids that may be flow through the tubular heating elementsinclude, but are not limited to, air, water, steam, helium, carbondioxide or other fluids. In some embodiments, a hot fluid, such ascarbon dioxide or helium, flows through the tubular heating elements toprovide heat to the formation. The hot fluid may be used to provide heatto the formation before electrical heating is used to provide heat tothe formation. In some embodiments, the hot fluid is used to provideheat in addition to electrical heating. Using the hot fluid to provideheat to the formation in addition to providing electrical heating may beless expensive than using electrical heating alone to provide heat tothe formation. In some embodiments, water and/or steam flows through thetubular heating element to recover heat from the formation. The heatedwater and/or steam may be used for solution mining and/or otherprocesses.

Transition sections 892 may couple heating elements 804 to sections 888.In certain embodiments, transition sections 892 include material thathas a high electrical conductivity but is corrosion resistant, such as347 stainless steel over copper. In an embodiment, transition sectionsinclude a composite of stainless steel clad over copper. Transitionsections 892 inhibit overheating of copper and/or insulation in sections888.

FIG. 146 depicts a representational top view of an embodiment of asurface pattern of heaters depicted in FIG. 145. Heaters 880A-L may bearranged in a repeating triangular pattern on the surface of theformation, as shown in FIG. 146. A triangle may be formed by heaters880A, 880B, and 880C and a triangle formed by heaters 880C, 880D, and880E. In some embodiments, heaters 880A-L are arranged in a straightline on the surface of the formation. Heaters 880A-L have first endportions at first location 878 on the surface and second end portions atsecond location 884 on the surface. Heaters 880A-L are arranged suchthat (a) the patterns at first location 878 and second location 884correspond to each other, (b) the spacing between heaters is maintainedat the two locations on the surface, and/or (c) the heaters all havesubstantially the same length (substantially the same horizontaldistance between the end portions of the heaters on the surface as shownin the top view of FIG. 146).

As depicted in FIGS. 145 and 146, cables 894, 896 may be coupled totransformer 900 and one or more heater units, such as the heater unitincluding heaters 880A, 880B, 880C. Cables 894, 896 may carry a largeamount of power. In certain embodiments, cables 894, 896 are capable ofcarrying high currents with low losses. For example, cables 894, 896 maybe thick copper or aluminum conductors. The cables may also have thickinsulation layers. In some embodiments, cable 894 and/or cable 896 maybe superconducting cables. The superconducting cables may be cooled byliquid nitrogen. Superconducting cables are available from Superpower,Inc. (Schenectady, N.Y., U.S.A.). Superconducting cables may minimizepower loss and reduce the size of the cables needed to coupletransformer 900 to the heaters.

In certain embodiments, bus bar 898A is coupled to first end portions ofheaters 880A-L and bus bar 898B is coupled to second end portions ofheaters 880A-L. Bus bars 898A,B electrically couple heaters 880A-L tocables 894, 896 and transformer 900. Bus bars 898A,B distribute power toheaters 880A-L. In certain embodiments, bus bars 898A,B are capable ofcarrying high currents with low losses. In some embodiments, bus bars898A,B are made of superconducting material such as the superconductormaterial used in cables 894, 896.

As shown in FIGS. 145 and 146, heaters 880A-L are coupled to a singletransformer 900. In certain embodiments, transformer 900 is a source oftime-varying current. In certain embodiments, transformer 900 is anelectrically isolated, single-phase transformer. In certain embodiments,transformer 900 provides power to heaters 880A-L from an isolatedsecondary phase of the transformer. First end portions of heaters 880A-Lmay be coupled to one side of transformer 900 while second end portionsof the heaters are coupled to the opposite side of the transformer.Transformer 900 provides a substantially common voltage to the first endportions of heaters 880A-L and a substantially common voltage to thesecond end portions of heaters 880A-L. In certain embodiments,transformer 900 applies a voltage potential to the first end portions ofheaters 880A-L that is opposite in polarity and substantially equal inmagnitude to a voltage potential applied to the second end portions ofthe heaters. For example, a +660 V potential may be applied to the firstend portions of heaters 880A-L and a −660 V potential applied to thesecond end portions of the heaters at a selected point on the wave oftime-varying current (such as AC or modulated DC). Thus, the voltages atthe two end portion of the heaters may be equal in magnitude andopposite in polarity with an average voltage that is substantially atground potential.

Applying the same voltage potentials to the end portions of all heaters880A-L produces voltage potentials along the lengths of the heaters thatare substantially the same along the lengths of the heaters. FIG. 147depicts a cross-section representation, along a vertical plane, such asthe plane A-A shown in FIG. 145, of substantially u-shaped heaters in ahydrocarbon layer. The voltage potential at the cross-sectional pointshown in FIG. 147 along the length of heater 880A is substantially thesame as the voltage potential at the corresponding cross-sectionalpoints on heaters 880A-L shown in FIG. 147. At lines equidistant betweenheater wellheads, the voltage potential is approximately zero. Otherwells, such as production wells or monitoring wells, may be locatedalong these zero voltage potential lines, if desired. Production wells206 located close to the overburden may be used to transport formationfluid that is initially in a vapor phase to the surface. Productionwells located close to a bottom of the heated portion of the formationmay be used to transport formation fluid that is initially in a liquidphase to the surface.

In certain embodiments, the voltage potential at the midpoint of heaters880A-L is about zero. Having similar voltage potentials along thelengths of heaters 880A-L inhibits current leakage between the heaters.Thus, there is little or no current flow in the formation and theheaters may have long lengths as described above. Having the oppositepolarity and substantially equal voltage potentials at the end portionsof the heaters also halves the voltage applied at either end portion ofthe heater versus having one end portion of the heater grounded and oneend portion at full potential. Reducing (halving) the voltage potentialapplied to an end portion of the heater generally reduces currentleakage, reduces insulator requirements, and/or reduces arcing distancesbecause of the lower voltage potential to ground applied at the endportions of the heaters.

In certain embodiments, substantially vertical heaters are used toprovide heat to the formation. Opposite polarity and substantially equalvoltage potentials, as described above, may be applied to the endportions of the substantially vertical heaters. FIG. 148 depicts aside-view representation of substantially vertical heaters coupled to asubstantially horizontal wellbore. Heaters 880A, 880B, 880C, 880D, 880E,880F are located substantially vertical in hydrocarbon layer 380. Firstend portions of heaters 880A, 880B, 880C, 880D, 880E, 880F are coupledto bus bar 898A on a surface of the formation. Second end portions ofheaters 880A, 880B, 880C, 880D, 880E, 880F are coupled to bus bar 898Bin contacting section 808.

Bus bar 898B may be a bus bar located in a substantially horizontalwellbore in contacting section 808. Second end portions of heaters 880A,880B, 880C, 880D, 880E, 880F may be coupled to bus bar 898B by anymethod described herein or any method known in the art. For example,containers with thermite powder are coupled to bus bar 898B (forexample, by welding or brazing the containers to the bus bar), endportions of heaters 880A, 880B, 880C, 880D, 880E, 880F are placed insidethe containers, and the thermite powder is activated to electricallycouple the heaters to the bus bar. The containers may be coupled to busbar 898B by, for example, placing the containers in holes or recesses inbus bar 898B or coupled to the outside of the bus bar and then brazingor welding the containers to the bus bar.

Bus bar 898A and bus bar 898B may be coupled to transformer 900 withcables 894, 896, as described above. Transformer 900 may providevoltages to bar 898A and bus bar 898B as described above for theembodiments depicted in FIGS. 145 and 146. For example, transformer 900may apply a voltage potential to the first end portions of heaters880A-F that is opposite in polarity and substantially equal in magnitudeto a voltage potential applied to the second end portions of theheaters. Applying the same voltage potentials to the end portions of allheaters 880A-F may produce voltage potentials along the lengths of theheaters that are substantially the same along the lengths of theheaters. Applying the same voltage potentials to the end portions of allheaters 880A-F may inhibit current leakage between the heaters and/orinto the formation.

In certain embodiments, it may be advantageous to allow some currentleakage into the formation during early stages of heating to heat theformation at a faster rate. Current leakage from the heaters into theformation electrically heats the formation directly. The formation isheated by direct electrical heating in addition to conductive heatprovided by the heaters. The formation (the hydrocarbon layer) may havean initial electrical resistance that averages at least 10 ohm·m. Insome embodiments, the formation has an initial electrical resistance ofat least 100 ohm·m or of at least 300 ohm·m. Direct electrical heatingis achieved by having opposite potentials applied to adjacent heaters inthe hydrocarbon layer. Current may be allowed to leak into the formationuntil a selected temperature is reached in the heaters or in theformation. The selected temperature may be below or near the temperaturethat water proximate one or more heaters boils off. After water boilsoff, the hydrocarbon layer is substantially electrically isolated fromthe heaters and direct heating of the formation is inefficient. Afterthe selected temperature is reached, the voltage potential is applied inthe opposite polarity and substantially equal magnitude manner describedabove for FIGS. 145 and 146 so that adjacent heaters will have the samevoltage potential along their lengths.

Current is allowed to leak into the formation by reversing the polarityof one or more heaters shown in FIG. 146 so that a first group ofheaters has a positive voltage potential at first location 878 and asecond group of heaters has a negative voltage potential at the firstlocation. The first end portions, at first location 878, of a firstgroup of heaters (for example, heaters 880A, 880B, 880D, 880E, 880G,880H, 880J, 880K, depicted in FIG. 146) are applied with a positivevoltage potential that is substantially equal in magnitude to a negativevoltage potential applied to the second end portions, at second location884, of the first group of heaters. The first end portions, at firstlocation 878, of the second group of heaters (for example, heaters 880C,880F, 880I, 880L) are applied with a negative voltage potential that issubstantially equal in magnitude to the positive voltage potentialapplied to the first end portions of the first group of heaters.Similarly, the second end portions, at second location 884, of thesecond group of heaters are applied with a positive voltage potentialsubstantially equal in magnitude to the negative potential applied tothe second end portions of the first group of heaters. After theselected temperature is reached, the first end portions of both groupsof heaters are applied with voltage potential that is opposite inpolarity and substantially similar in magnitude to the voltage potentialapplied to the second end portions of both groups of heaters.

In some embodiments, heating elements 804 have a thin electricallyinsulating layer, described above, to inhibit current leakage from theheating elements. In some embodiments, the thin electrically insulatinglayer is aluminum oxide or thermal spray coated aluminum oxide. In someembodiments, the thin electrically insulating layer is an enamel coatingof a ceramic composition. The thin electrically insulating layer mayinhibit heating elements of a three-phase heater from leaking currentbetween the elements, from leaking current into the formation, and fromleaking current to other heaters in the formation. Thus, the three-phaseheater may have a longer heater length.

In certain embodiments, a heater becomes electrically isolated from theformation because the heater has little or no voltage potential on theoutside of the heater. FIG. 149 depicts an embodiment of a substantiallyu-shaped heater that electrically isolates itself from the formation.Heater 880 has a first end portion at a first opening on surface 550 anda second end portion at a second opening on the surface. In someembodiments, heater 880 has only one end portion coupled to the surface.

Heater 880 includes heating element 804 located in hydrocarbon layer380. Heating element 804 is a ferromagnetic conduit heating element orferromagnetic tubular heating element. In certain embodiments, heatingelement 804 is a temperature limited heater tubular heating element. Incertain embodiments, heating element 804 is a 9% by weight to 13% byweight chromium stainless steel tubular such as a 410 stainless steeltubular, aT/P91 stainless steel tubular, or a T/P92 stainless steeltubular. Heating element 804 is coupled to sections 888. Sections 888are located in overburden 382. Sections 888 include higher electricalconductivity materials such as copper or aluminum. In certainembodiments, sections 888 are copper clad inside carbon steel.

Center conductor 902 is located at or near a center of heating element804. In one embodiment, center conductor 902 is an insulated conductor(such as a mineral insulated conductor with a copper core, magnesiumoxide insulation, and a stainless steel sheath). In an alternativeembodiment, center conductor 902 is a conductor separated from heatingelement 804 by one or more electrically-insulating centralizers so thatthe heater is in a conductor-in-conduit configuration. The centralizersmay include silicon nitride or another electrically insulating material.

Center conductor 902 is electrically coupled to heating element 804 atan end portion of the center conductor and the heating element atsurface 550 (as shown by coupling 904 in FIG. 149). Center conductor 902is used as a return conductor for heating element 804 so that current inthe center conductor flows in an opposite direction from current in theheating element. The magnetic field generated by current flow in centerconductor 902 substantially confines the flow of electrons and heatgeneration to the inside of heating element 804 below the Curietemperature of the ferromagnetic material in the heating element. Thus,the outside of heating element 804 is at substantially zero potentialand the heating element is electrically isolated from the formation andany adjacent heater or heating element. In some embodiments, a fluid,such as carbon dioxide or another fluid with a high heat capacity, flowsthrough heating element 804 to preheat the formation and/or to recoverheat from the heating element.

FIGS. 150A and 150B depict an embodiment for using substantiallyu-shaped wellbores to time sequence heat two layers in a hydrocarboncontaining formation. In FIG. 150A, substantially horizontal opening378A is formed in hydrocarbon layer 380A extending from relativelyvertical openings 378. Hydrocarbon layer 380A is separated fromhydrocarbon layer 380B by impermeable zone 468. Impermeable zone 468provides a substantially impermeable seal for fluid flow betweenhydrocarbon layer 380A and hydrocarbon layer 380B. In certainembodiments (for example, in an oil shale formation), hydrocarbon layer380A has a higher richness than hydrocarbon layer 380B.

Heating element 804A is placed in opening 378A in hydrocarbon layer380A. Overburden casing 680 is placed along the relatively verticalwalls of openings 378 in hydrocarbon layer 380B. Overburden casing 680inhibits heat transfer to hydrocarbon layer 380B while heat is providedto hydrocarbon layer 380A by heating element 804A. Heating element 804Ais used to provide heat to hydrocarbon layer 380A. Formation fluids,such as pyrolyzed hydrocarbons, may be produced from hydrocarbon layer380A.

Heat may be provided to hydrocarbon layer 380A by heating element 804Afor a selected length of time. The selected length of time may be basedon a variety of factors including, but not limited to, formationcharacteristics, present or future economic factors, or capital costs.For example, for an oil shale formation, hydrocarbon layer 380A may havea richness of about 0.12 L/kg (30.5 gals/ton) so the layer is heated forabout 25 years. Production of formation fluids from hydrocarbon layer380A may continue from the layer until production slows down to anuneconomical rate.

After hydrocarbon layer 380A is heated for the selected time, heatingelement 804A is turned off. Heating element 804A may be pulled firmly(for example, yanked) upwards so that the heating element breaks off atlinks 906. Links 906 may be weak links designed to pull apart when aselected or sufficient amount of pulling force is applied to the links.The upper portions of heating element 804A are then pulled out of theformation and the substantially horizontal portion of heating element804A is left in opening 378A, as shown in FIG. 150B. In someembodiments, only one link 906 may be broken so that the upper portionabove the one link can be removed and the remaining portions of theheater can be removed by pulling on the opposite end of the heater.Thus, the entire length of heating element 804A may be removed from theformation.

After upper portions of heating element 804A are removed from openings378, plugs 908 may be placed into openings 378 at a selected location inhydrocarbon layer 380B, as depicted in FIG. 150B. In certainembodiments, plugs 908 are placed into openings 378 at or nearimpermeable zone 468. Packing 520 may be placed into openings 378 aboveplugs 908. In some embodiments, packing 520 is filled into openings 378without plugs in the openings.

After plugs 908 and/or packing 520 is set into place in openings 378,substantially horizontal opening 378B may be formed in hydrocarbon layer380B through casing 680. Heating element 804B is placed into opening378B. Heating element 804B is used to provide heat to hydrocarbon layer380B. Formation fluids, such as pyrolyzed hydrocarbons, may be producedfrom hydrocarbon layer 380B.

Heating hydrocarbon layers 380A, 380B in the time-sequenced mannerdescribed above may be more economical than producing from only onelayer or using vertical heaters to provide heat to the layerssimultaneously. Using relatively vertical openings 378 to access bothhydrocarbon layers at different times may save on capital costsassociated with forming openings in the formation and providing surfacefacilities to power the heating elements. Heating hydrocarbon layer 380Afirst before heating hydrocarbon layer 380B may improve the economics oftreating the formation (for example, the net present value of a projectto treat the formation). In addition, impermeable zone 468 and packing520 may provide a seal for hydrocarbon layer 380A after heating andproduction from the layer. This seal may be useful for abandonment ofthe hydrocarbon layer after treating the hydrocarbon layer.

In certain embodiments, portions of the wellbore that extend through theoverburden include casings. The casings may include materials thatinhibit inductive effects in the casings. Inhibiting inductive effectsin the casings may inhibit induced currents in the casing and/or reduceheat losses to the overburden. In some embodiments, the overburdencasings may include non-metallic materials such as fiberglass,polyvinylchloride (PVC), chlorinated PVC (CPVC), or high-densitypolyethylene (HDPE). HDPEs with working temperatures in a usable rangeinclude HDPEs available from Dow Chemical Co., Inc. (Midland, Mich.,U.S.A.). In some embodiments, overburden casings may includenon-magnetic metals such as aluminum or non-magnetic alloys such asmanganese steels having at least 10% manganese, iron aluminum alloyswith at least 18% aluminum, or austentitic stainless steels such as 304stainless steel or 316 stainless steel. In some embodiments, overburdencasings may include carbon steel or other ferromagnetic material coupledon the inside diameter to a highly conductive non-ferromagnetic metal(for example, copper or aluminum) to inhibit inductive effects or skineffects.

In certain embodiments, wellheads for the wellbores may be made of oneor more non-ferromagnetic materials. The wellheads may includefiberglass, PVC, CPVC, HDPE, and/or non-magnetic alloys or metals. Usingnon-ferromagnetic materials in the wellhead may inhibit undesiredheating of components in the wellhead. Ferromagnetic materials used inthe wellhead may be electrically and/or thermally insulated from othercomponents of the wellhead. In some embodiments, an inert gas (forexample, nitrogen or argon) is purged inside the wellhead and/or insideof casings to inhibit reflux of heated gases into the wellhead and/orthe casings.

In some embodiments, two or more substantially horizontal wellbores arebranched off of a first substantially vertical wellbore drilleddownwards from a first location on a surface of the formation. Thesubstantially horizontal wellbores may be substantially parallel througha hydrocarbon layer. The substantially horizontal wellbores mayreconnect at a second substantially vertical wellbore drilled downwardsat a second location on the surface of the formation. Having multiplewellbores branching off of a single substantially vertical wellboredrilled downwards from the surface reduces the number of openings madeat the surface of the formation.

In some embodiments, the temperature limited heater includes a singleferromagnetic conductor with current returning through the formation.The heating element may be a ferromagnetic tubular (in an embodiment,446 stainless steel (with 25% by weight chromium and a Curie temperatureabove 620° C.) clad over 304H, 316H, or 347H stainless steel) thatextends through the heated target section and makes electrical contactto the formation in an electrical contacting section. The electricalcontacting section may be located below a heated target section in theunderburden of the formation. In an embodiment, the electricalcontacting section is a section 60 m deep with a larger diameter thanthe heater wellbore. The tubular in the electrical contacting section isa high electrical conductivity metal. The annulus in the electricalcontacting section may be filled with a contact material/solution suchas brine or other materials that enhance electrical contact with theformation (for example, metal beads, hematite, and/or graphite basedcement). The electrical contacting section may be located in a lowresistivity brine saturated zone (with higher porosity) to maintainelectrical contact through the brine. In the electrical contactingsection, the tubular diameter may also be increased to allow maximumcurrent flow into the formation with lower heat dissipation in thefluid. Current may flow through the ferromagnetic tubular in the heatedsection and heat the tubular.

FIG. 151 depicts an embodiment of a temperature limited heater withcurrent return through the formation. Heating element 804 may be placedin opening 378 in hydrocarbon layer 380. Heating element 804 may be 446stainless steel clad over a 304H stainless steel tubular that extendsthrough hydrocarbon layer 380. Heating element 804 may be coupled tocontacting element 806. Contacting element 806 may have a higherelectrical conductivity than heating element 804. Contacting element 806may be placed in contacting section 808 below hydrocarbon layer 380.Contacting element 806 may make electrical contact with the earth inelectrical contacting section 808. Contacting element 806 may be placedin contacting wellbore 910. Contacting element 806 may have a diameterbetween about 10 cm and about 20 cm (for example, about 15 cm). Thediameter of contacting element 806 may be sized to increase contact areabetween contacting element 806 and contact solution 814. The contactarea may be increased by increasing the diameter of contacting element806. Increasing the diameter of contacting element 806 may increase thecontact area without adding excessive cost to installation and use ofthe contacting element, contacting wellbore 910, and/or contact solution814. Increasing the diameter of contacting element 806 may allowsufficient electrical contact to be maintained between the contactingelement and contacting section 808. Increasing the contact area may alsoinhibit evaporation or reduction of contact solution 814.

Contacting wellbore 910 may be, for example, a section of about 60 mdeep with a larger diameter wellbore than opening 378. The annulus ofcontacting wellbore 910 may be filled with contact solution 814. Contactsolution 814 may be brine or other material (such as graphite basedcement, electrically conducting particles such as hematite, ormetal-coated sand or beads) that enhances electrical contact incontacting section 808. In some embodiments, contacting section 808 is alow resistivity brine saturated zone that maintains electrical contactthrough the brine. Contacting wellbore 910 may be under-reamed to alarger diameter (for example, a diameter between about 25 cm and about50 cm) to allow maximum current flow into contacting section 808 withlow heat output. Current may flow through heating element 804, boilingmoisture from the wellbore, and heating until the heat output reducesnear or at the Curie temperature.

In an embodiment, three-phase temperature limited heaters are made withcurrent connection through the formation. Each heater includes a singleCurie temperature heating element with an electrical contacting sectionin a brine saturated zone below a heated target section. In anembodiment, three such heaters are connected electrically at the surfacein a three-phase wye configuration. The heaters may be deployed in atriangular pattern from the surface. In certain embodiments, the currentreturns through the earth to a neutral point between the three heaters.The three-phase Curie heaters may be replicated in a pattern that coversthe entire formation.

FIG. 152 depicts an embodiment of a three-phase temperature limitedheater with current connection through the formation. Legs 798, 800, 802may be placed in the formation. Each leg 798, 800, 802 may have heatingelement 804 that is placed in opening 378 in hydrocarbon layer 380. Eachleg may have contacting element 806 placed in contact solution 814 incontacting wellbore 910. Each contacting element 806 may be electricallycoupled to electrical contacting section 808 through contact solution814. Legs 798, 800, 802 may be connected in a wye configuration thatresults in a neutral point in electrical contacting section 808 betweenthe three legs. FIG. 153 depicts an aerial view of the embodiment ofFIG. 152 with neutral point 912 shown positioned centrally among legs798, 800, 802.

FIG. 154 depicts an embodiment of three temperature limited heaterselectrically coupled to a horizontal wellbore in the formation. Wellbore420 may have a substantially horizontal portion in contacting section808. Openings 378 may be directionally drilled to intersect wellbore 420in contacting wellbores 910. In some embodiments, wellbore 420 isdirectionally drilled to intersect openings 378 in contacting wellbores910. Contacting wellbores 910 may be underreamed. Underreaming mayincrease the likelihood of intersection between openings 378 andwellbore 420 during drilling and/or increase the contact volume incontacting wellbores 910.

In certain embodiments, legs 798, 800, 802 are coupled in a three-phasewye configuration. In some embodiments, legs 798, 800, 802, along withone or more other legs, are coupled through wellbore 420 in a singlephase configuration in which the legs are alternately biased positivelyand negatively so that current alternately runs up and down the legs. Insome embodiments, legs 798, 800, 802 are single phase heaters withcurrent returning to the surface through wellbore 420.

In certain embodiments, legs 798, 800, 802 are electrically coupled incontacting wellbores 910 using contact solution 814. Contact solution814 may be located in individual contacting wellbores 910 or may belocated along the length of the horizontal portion of wellbore 420. Insome embodiments, electrical contact is made between legs 798, 800, 802and/or materials in wellbore 420 through other methods (for example,contactors or contacting elements such as funnels, guides, or catchers).

FIG. 155 depicts an embodiment of a three-phase temperature limitedheater with a common current connection through the formation. In FIG.155, each leg 798, 800, 802 couples to a single contacting element 806in a single contacting wellbore 910. Legs 798 and 802 are directionallydrilled to intercept leg 800 in wellbore 910. Contacting element 806 mayinclude funnels, guides, or catchers for allowing each leg to beinserted into the contacting element. In some embodiments, graphitebased cement is used for contact solution 814.

A section of heater through a high thermal conductivity zone may betailored to deliver more heat dissipation in the high thermalconductivity zone. Tailoring of the heater may be achieved by changingcross-sectional areas of the heating elements (for example, by changingratios of copper to iron), and/or using different metals in the heatingelements. Thermal conductance of the insulation layer may also bemodified in certain sections to control the thermal output to raise orlower the apparent Curie temperature zone.

In an embodiment, the temperature limited heater includes a hollow coreor hollow inner conductor. Layers forming the heater may be perforatedto allow fluids from the wellbore (for example, formation fluids orwater) to enter the hollow core. Fluids in the hollow core may betransported (for example, pumped or gas lifted) to the surface throughthe hollow core. In some embodiments, the temperature limited heaterwith the hollow core or the hollow inner conductor is used as aheater/production well or a production well. Fluids such as steam may beinjected into the formation through the hollow inner conductor.

In certain embodiments, a temperature limited heater is utilized forheavy oil applications (for example, treatment of relatively permeableformations or tar sands formations). A temperature limited heater mayprovide a relatively low Curie temperature so that a maximum averageoperating temperature of the heater is less than 350° C., 300° C., 250°C., 225° C., 200° C., or 150° C. In an embodiment (for example, for atar sands formation), a maximum temperature of the heater is less thanabout 250° C. to inhibit olefin generation and production of othercracked products. In some embodiments, a maximum temperature of theheater above about 250° C. is used to produce lighter hydrocarbonproducts. For example, the maximum temperature of the heater may be ator less than about 500° C.

A heater may heat a volume of formation adjacent to a productionwellbore (a near production wellbore region) so that the temperature offluid in the production wellbore and in the volume adjacent to theproduction wellbore is less than the temperature that causes degradationof the fluid. The heat source may be located in the production wellboreor near the production wellbore. In some embodiments, the heat source isa temperature limited heater. In some embodiments, two or more heatsources may supply heat to the volume. Heat from the heat source mayreduce the viscosity of crude oil in or near the production wellbore. Insome embodiments, heat from the heat source mobilizes fluids in or nearthe production wellbore and/or enhances the radial flow of fluids to theproduction wellbore. In some embodiments, reducing the viscosity ofcrude oil allows or enhances gas lifting of heavy oil (approximately atmost 10° API gravity oil) or intermediate gravity oil (approximately 12°to 20° API gravity oil) from the production wellbore. In certainembodiments, the initial API gravity of oil in the formation is at most10°, at most 200, at most 25°, or at most 300. In certain embodiments,the viscosity of oil in the formation is at least 0.05 Pa·s (50 cp). Insome embodiments, the viscosity of oil in the formation is at least 0.10Pa·s (100 cp), at least 0.15 Pa·s (150 cp), or at least at least 0.20Pa·s (200 cp). Large amounts of natural gas may have to be utilized toprovide gas lift of oil with viscosities above 0.05 Pa·s. Reducing theviscosity of oil at or near the production wellbore in the formation toa viscosity of 0.05 Pa·s (50 cp), 0.03 Pa·s (30 cp), 0.02 Pa·s (20 cp),0.01 Pa·s (10 cp), or less (down to 0.001 Pa·s (1 cp) or lower) lowersthe amount of natural gas needed to lift oil from the formation. In someembodiments, reduced viscosity oil is produced by other methods such aspumping.

The rate of production of oil from the formation may be increased byraising the temperature at or near a production wellbore to reduce theviscosity of the oil in the formation in and adjacent to the productionwellbore. In certain embodiments, the rate of production of oil from theformation is increased by 2 times, 3 times, 4 times, or greater up to 20times over standard cold production, which has no external heating offormation during production. Certain formations may be more economicallyviable for enhanced oil production using the heating of the nearproduction wellbore region. Formations that have a cold production rateapproximately between 0.05 m³/(day per meter of wellbore length) and0.20 m³/(day per meter of wellbore length) may have significantimprovements in production rate using heating to reduce the viscosity inthe near production wellbore region. In some formations, productionwells up to 775 m, up to 1000 m, or up to 1500 m in length are used. Forexample, production wells between 450 m and 775 m in length are used,between 550 m and 800 m are used, or between 650 m and 900 m are used.Thus, a significant increase in production is achievable in someformations. Heating the near production wellbore region may be used informations where the cold production rate is not between 0.05 m³/(dayper meter of wellbore length) and 0.20 m³/(day per meter of wellborelength), but heating such formations may not be as economicallyfavorable. Higher cold production rates may not be significantlyincreased by heating the near wellbore region, while lower productionrates may not be increased to an economically useful value.

Using the temperature limited heater to reduce the viscosity of oil ator near the production well inhibits problems associated withnon-temperature limited heaters and heating the oil in the formation dueto hot spots. One possible problem is that non-temperature limitedheaters can causing coking of oil at or near the production well if theheater overheats the oil because the heaters are at too high atemperature. Higher temperatures in the production well may also causebrine to boil in the well, which may lead to scale formation in thewell. Non-temperature limited heaters that reach higher temperatures mayalso cause damage to other wellbore components (for example, screensused for sand control, pumps, or valves). Hot spots may be caused byportions of the formation expanding against or collapsing on the heater.In some embodiments, the heater (either the temperature limited heateror another type of non-temperature limited heater) has sections that arelower because of sagging over long heater distances. These lowersections may sit in heavy oil or bitumen that collects in lower portionsof the wellbore. At these lower sections, the heater may develop hotspots due to coking of the heavy oil or bitumen. A standardnon-temperature limited heater may overheat at these hot spots, thusproducing a non-uniform amount of heat along the length of the heater.Using the temperature limited heater may inhibit overheating of theheater at hot spots or lower sections and provide more uniform heatingalong the length of the wellbore.

In some embodiments, oil or bitumen cokes in a perforated liner orscreen in a heater/production wellbore (for example, coke may formbetween the heater and the liner or between the liner and theformation). Oil or bitumen may also coke in a toe section of a heel andtoe heater/production wellbore, as shown in and described below for FIG.165. A temperature limited heater may limit a temperature of aheater/production wellbore below a coking temperature to inhibit cokingin the well so that the wellbore does not plug up.

In certain embodiments, fluids in the relatively permeable formationcontaining heavy hydrocarbons are produced with little or nopyrolyzation of hydrocarbons in the formation. In certain embodiments,the relatively permeable formation containing heavy hydrocarbons is atar sands formation. The fluids produced from the formation aremobilized fluids. Producing mobilized fluids may be more economical thanproducing pyrolyzed fluids from the tar sands formation. Producingmobilized fluids may also increase the total amount of hydrocarbonsproduced from the tar sands formation.

FIG. 156 depicts a side view representation of an embodiment forproducing mobilized fluids from the tar sands formation. In anembodiment, heaters 880 are placed in an alternating triangular patternin hydrocarbon layer 380. Heaters 880 provide heat that mobilizeshydrocarbons (reduces the viscosity of the hydrocarbons) in hydrocarbonlayer 380. Heat provided by heaters 880 is controlled so that little orno pyrolyzation occurs in hydrocarbon layer 380. Fluids mobilized inhydrocarbon layer 380 tend to flow towards the bottommost heaters in thehydrocarbon layer because of gravity and the heat gradient establishedby the heaters. The heat diffuses between the heaters to create a flowpath between the heaters for mobilized fluids. This flow path, becauseof the triangular pattern that provides superposition of heat andbecause of gravity, directs mobilized fluids downwards towardsproduction wells 206. Hydrocarbon layer 380 should have substantialvertical permeability to allow mobilized fluids to drain to productionwells 206.

Production wells 206 are located below heaters 880 in the lower portionof hydrocarbon layer 380. Production wells 206 are located below andnear heaters 880 at the bottom vertex of the triangular pattern ofheaters. Production wells 206 are substantially vertically below thebottommost heaters in hydrocarbon layer 380. Locating production wells206 substantially vertically below the bottommost heaters providesefficient collection of mobilized fluids in hydrocarbon layer 380. Incertain embodiments, production wells 206 are located within about 2 m,within about 5 m, or within about 7 m of the bottommost heaters. In someembodiments, some heat is provided in production wells 206. Providingheat in production wells 206 maintains the mobility of the fluids in theproduction wells.

FIG. 157 depicts a representation of an embodiment for producinghydrocarbons from the tar sands formation. Hydrocarbon layer 380includes one or more portions with heavy hydrocarbons. Hydrocarbons maybe produced from hydrocarbon layer 380 using more than one process. Incertain embodiments, hydrocarbons are produced from a first portion ofhydrocarbon layer 380 using a steam injection process (for example,cyclic steam injection or steam-assisted gravity drainage) and a secondportion of the hydrocarbon layer using an in situ conversion process. Inthe steam injection process, steam is injected into the first portion ofhydrocarbon layer 380 through injection well 916. First hydrocarbons areproduced from the first portion through production well 206A. The firsthydrocarbons include hydrocarbons mobilized by the injection of steam.In certain embodiments, the first hydrocarbons have an API gravity of atmost 10°, at most 8°, or at most 6°.

Heaters 880 are used to heat the second portion of hydrocarbon layer 380to pyrolysis temperatures. Second hydrocarbons are produced from thefirst portion through production well 206B. In certain embodiments, thesecond hydrocarbons include at least some pyrolyzed hydrocarbons. Incertain embodiments, the second hydrocarbons have an API gravity of atleast 15°, at least 200, or at least 25°.

Producing hydrocarbons through both processes increases the totalrecovery of hydrocarbons from hydrocarbon layer 380 and may be moreeconomical than using either process alone. In some embodiments, thefirst portion is treated with the in situ conversion process after thesteam injection process is completed. For example, after the steaminjection process no longer produces viable amounts of hydrocarbon fromthe first portion, the in situ conversion process may be used on thefirst portion.

Steam is provided to injection well 916 from facility 918. Facility 918is a steam and electricity cogeneration facility. Facility 918 may burnhydrocarbons in generators to make electricity. The electricitygenerated is used to provide electrical power for heaters 880. Wasteheat from the generators is used to make steam. In some embodiments,some of the hydrocarbons produced from the formation are used to providegas for heaters 880, if the heaters utilize gas to provide heat to theformation. The amount of electricity and steam generated by facility 918may be controlled to vary the production rate and/or quality ofhydrocarbons produced from the first portion and/or the second portionof hydrocarbon layer 380. The production rate and/or quality ofhydrocarbons produced from the first portion and/or the second portionmay be varied to produce a selected API gravity in a mixture made byblending the first hydrocarbons with the second hydrocarbons. The firsthydrocarbon and the second hydrocarbons may be blended after productionto produce the selected API gravity. The production from the firstportion and/or the second portion may be varied in response to changesin the marketplace for either first hydrocarbons, second hydrocarbons,and/or a mixture of the first and second hydrocarbons.

First hydrocarbons produced from production well 206A and/or secondhydrocarbons produced from production well 206B may be used as fuel forfacility 918. In some embodiments, first hydrocarbons and/or secondhydrocarbons are treated (for example, removing undesirable products)before being used as fuel for facility 918. The amount of firsthydrocarbons and second hydrocarbons used as fuel for facility 918 maybe determined, for example, by economics for the overall process, themarketplace for either first or second hydrocarbons, availability oftreatment facilities for either first or second hydrocarbons, and/ortransportation facilities available for either first or secondhydrocarbons. In some embodiments, most or all the hydrocarbon gasproduced from hydrocarbon layer 380 is used as fuel for facility 918.Burning all the hydrocarbon gas in facility 918 eliminates the need fortreatment and/or transportation of gases produced from hydrocarbon layer380.

The produced first hydrocarbons and the second hydrocarbons may betreated and/or blended in facility 920. In some embodiments, the firstand second hydrocarbons are blended to make a mixture that istransportable through a pipeline. In some embodiments, the first andsecond hydrocarbons are blended to make a mixture that is useable as afeedstock for a refinery. The amount of first and second hydrocarbonsproduced may be varied based on changes in the requirements fortreatment and/or blending of the hydrocarbons. In some embodiments,treated hydrocarbons are used in facility 918.

FIG. 158 depicts an embodiment for heating and producing from theformation with the temperature limited heater in a production wellbore.Production conduit 512 is located in wellbore 922. In certainembodiments, a portion of wellbore 922 is located substantiallyhorizontally in formation 444. In some embodiments, the wellbore islocated substantially vertically in the formation. In an embodiment,wellbore 922 is an open wellbore (an uncased wellbore). In someembodiments, the wellbore has a casing or liner with perforations oropenings to allow fluid to flow into the wellbore.

Conduit 512 may be made from carbon steel or more corrosion resistantmaterials such as stainless steel. Conduit 512 may include apparatus andmechanisms for gas lifting or pumping produced oil to the surface. Forexample, conduit 512 includes gas lift valves used in a gas liftprocess. Examples of gas lift control systems and valves are disclosedin U.S. Pat. No. 6,715,550 to Vinegar et al. and U.S. Patent ApplicationPublication Nos. 2002-0036085 to Bass et al. and 2003-0038734 to Hirschet al., each of which is incorporated by reference as if fully set forthherein. Conduit 512 may include one or more openings (perforations) toallow fluid to flow into the production conduit. In certain embodiments,the openings in conduit 512 are in a portion of the conduit that remainsbelow the liquid level in wellbore 922. For example, the openings are ina horizontal portion of conduit 512.

Heater 534 is located in conduit 512, as shown in FIG. 158. In someembodiments, heater 534 is located outside conduit 512, as shown in FIG.159. The heater located outside the production conduit may be coupled(strapped) to the production conduit. In some embodiments, more than oneheater (for example, two, three, or four heaters) are placed aboutconduit 512. The use of more than one heater may reduce bowing orflexing of the production conduit caused by heating on only one side ofthe production conduit. In an embodiment, heater 534 is a temperaturelimited heater. Heater 534 provides heat to reduce the viscosity offluid (such as oil or hydrocarbons) in and near wellbore 922. In certainembodiments, heater 534 raises the temperature of the fluid in wellbore922 up to a temperature of 250° C. or less (for example, 225° C., 200°C., or 150° C.). Heater 534 may be at higher temperatures (for example,275° C., 300° C., or 325° C.) because the heater provides heat toconduit 512 and there is some temperature differential between theheater and the conduit. Thus, heat produced from the heater does notraise the temperature of fluids in the wellbore above 250° C.

In certain embodiments, heater 534 includes ferromagnetic materials suchas Carpenter Temperature Compensator “32”, Alloy 42-6, Alloy 52, Invar36, or other iron-nickel or iron-nickel-chromium alloys. In certainembodiments, nickel or nickel-chromium alloys are used in heater 534. Insome embodiments, heater 534 includes a composite conductor with a morehighly conductive material such as copper on the inside of the heater toimprove the turndown ratio of the heater. Heat from heater 534 heatsfluids in or near wellbore 922 to reduce the viscosity of the fluids andincrease a production rate through conduit 512.

In certain embodiments, portions of heater 534 above the liquid level inwellbore 922 (such as the vertical portion of the wellbore depicted inFIGS. 158 and 159) have a lower maximum temperature than portions of theheater located below the liquid level. For example, portions of heater534 above the liquid level in wellbore 922 may have a maximumtemperature of 100° C. while portions of the heater located below theliquid level have a maximum temperature of 250° C. In certainembodiments, such a heater includes two or more ferromagnetic sectionswith different Curie temperatures to achieve the desired heatingpattern. Providing less heat to portions of wellbore 922 above theliquid level and closer to the surface may save energy.

In certain embodiments, heater 534 is electrically isolated on theheater's outside surface and allowed to move freely in conduit 512. Insome embodiments, electrically insulating centralizers are placed on theoutside of heater 534 to maintain a gap between conduit 512 and theheater.

In some embodiments, heater 534 is cycled (turned on and off) so thatfluids produced through conduit 512 are not overheated. In anembodiment, heater 534 is turned on for a specified amount of time untila temperature of fluids in or near wellbore 922 reaches a desiredtemperature (for example, the maximum temperature of the heater). Duringthe heating time (for example, 10 days, 20 days, or 30 days), productionthrough conduit 512 may be stopped to allow fluids in the formation to“soak” and obtain a reduced viscosity. After heating is turned off orreduced, production through conduit 512 is started and fluids from theformation are produced without excess heat being provided to the fluids.During production, fluids in or near wellbore 922 will cool down withoutheat from heater 534 being provided. When the fluids reach a temperatureat which production significantly slows down, production is stopped andheater 534 is turned back on to reheat the fluids. This process may berepeated until a desired amount of production is reached. In someembodiments, some heat at a lower temperature is provided to maintain aflow of the produced fluids. For example, low temperature heat (forexample, 100° C., 125° C., or 150° C.) may be provided in the upperportions of wellbore 922 to keep fluids from cooling to a lowertemperature.

FIG. 160 depicts an embodiment of a heating/production assembly that maybe located in a wellbore for gas lifting. Heating/production assembly924 may be located in a wellbore in the formation (for example, wellbore922 depicted in FIG. 158 or 159). Conduit 512 is located inside casing680. In an embodiment, conduit 512 is coiled tubing such as 6 cmdiameter coiled tubing. Casing 680 has a diameter between 10 cm and 25cm (for example, a diameter of 14 cm, 16 cm, or 18 cm). Heater 534 iscoupled to an end of conduit 512. In some embodiments, heater 534 islocated inside conduit 512. In some embodiments, heater 534 is aresistive portion of conduit 512. In some embodiments, heater 534 iscoupled to a length of conduit 512.

Opening 926 is located at or near a junction of heater 534 and conduit512. In some embodiments, opening 926 is a slot or a slit in conduit512. In some embodiments, opening 926 includes more than one opening inconduit 512. Opening 926 allows production fluids to flow into conduit512 from a wellbore. Perforated casing 928 allows fluids to flow intothe heating/production assembly 924. In certain embodiments, perforatedcasing 928 is a wire wrapped screen.

In one embodiment, perforated casing 928 is a 9 cm diameter wire wrappedscreen.

Perforated casing 928 may be coupled to casing 680 with packing material520. Packing material 520 inhibits fluids from flowing into casing 680from outside perforated casing 928. Packing material 520 may also beplaced inside casing 680 to inhibit fluids from flowing up the annulusbetween the casing and conduit 512. Seal assembly 920 is used to sealconduit 512 to packing material 520. Seal assembly 920 may fix aposition of conduit 512 along a length of a wellbore. In someembodiments, seal assembly 920 allows for unsealing of conduit 512 sothat the production conduit and heater 534 may be removed from thewellbore.

Feedthrough 932 is used to pass lead-in cable 692 to supply power toheater 534. Lead-in cable 692 may be secured to conduit 512 with clamp934. In some embodiments, lead-in cable 692 passes through packingmaterial 520 using a separate feedthrough.

A lifting gas (for example, natural gas, methane, carbon dioxide,propane, and/or nitrogen) may be provided to the annulus between conduit512 and casing 680. Valves 936 are located along a length of conduit 512to allow gas to enter the production conduit and provide for gas liftingof fluids in the production conduit. The lifting gas may mix with fluidsin conduit 512 to lower the density of the fluids and allow for gaslifting of the fluids out of the formation. In certain embodiments,valves 936 are located in or near the overburden section of theformation so that gas lifting is provided in the overburden section. Insome embodiments, fluids are produced through the annulus betweenconduit 512 and casing 680 and the lifting gas is supplied throughvalves 936.

In an embodiment, fluids are produced using a pump coupled to conduit512. The pump may be a submersible pump (for example, an electric or gaspowered submersible pump). In some embodiments, a heater is coupled toconduit 512 to maintain the reduced viscosity of fluids in the conduitand/or the pump.

In certain embodiments, an additional conduit such as an additionalcoiled tubing conduit is placed in the formation. Sensors may be placedin the additional conduit. For example, a production logging tool may beplaced in the additional conduit to identify locations of producingzones and/or to assess flow rates. In some embodiments, a temperaturesensor (for example, a distributed temperature sensor, a fiber opticsensor, and/or an array of thermocouples) is placed in the additionalconduit to determine a subsurface temperature profile.

Some embodiments of the heating/production assembly are used in a wellthat preexists (for example, the heating/production assembly isretrofitted for a preexisting production well, heater well, ormonitoring well). An example of the heating/production assembly that maybe used in the preexisting well is depicted in FIG. 161. Somepreexisting wells include a pump. The pump in the preexisting well maybe left in the heating/production well retrofitted with theheating/production assembly.

FIG. 161 depicts an embodiment of the heating/production assembly thatmay be located in the wellbore for gas lifting. In FIG. 161, conduit 512is located in outside production conduit 938. In an embodiment, outsideproduction conduit 938 is 11.4 cm diameter production tubing. Casing 680has a diameter of 24.4 cm. Perforated casing 928 has a diameter of 11.4cm. Seal assembly 920 seals conduit 512 inside outside productionconduit 938. In an embodiment, pump 518 is a jet pump such as abottomhole assembly jet pump.

FIG. 162 depicts another embodiment of a heating/production assemblythat may be located in a wellbore for gas lifting. Heater 534 is locatedinside perforated casing 928. Heater 534 is coupled to lead-in cable 692through a feedthrough in packing material 520. Production conduit 512extends through packing material 520. Pump 518 is located along conduit512. In certain embodiments, pump 518 is a jet pump or a bean pump.Valves 936 are located along conduit 512 for supplying lift gas to theconduit.

In some embodiments, heat is inhibited from transferring into conduit512. FIG. 163 depicts an embodiment of conduit 512 and heaters 534 thatinhibit heat transfer into the conduit. Heaters 534 are coupled toconduit 512. Heaters 534 include ferromagnetic sections 622 andnon-ferromagnetic sections 624. Ferromagnetic sections 622 provide heatat a temperature that reduces the viscosity of fluids in or near awellbore. Non-ferromagnetic sections 624 provide little or no heat. Incertain embodiments, ferromagnetic sections 622 and non-ferromagneticsections 624 are 6 m in length. In some embodiments, ferromagneticsections 622 and non-ferromagnetic sections 624 are between 3 m and 12 min length, between 4 m and 11 m in length, or between 5 m and 10 m inlength. In certain embodiments, non-ferromagnetic sections 624 includeperforations 940 to allow fluids to flow to conduit 512. In someembodiments, heater 534 is positioned so that perforations are notneeded to allow fluids to flow to conduit 512.

Conduit 512 may have perforations 940 to allow fluid to enter theconduit. Perforations 940 coincide with non-ferromagnetic sections 624of heater 534. Sections of conduit 512 that coincide with ferromagneticsections 622 include insulation conduit 942. Conduit 942 may be a vacuuminsulated tubular. For example, conduit 942 may be a vacuum insulatedproduction tubular available from Oil Tech Services, Inc. (Houston,Tex., U.S.A.). Conduit 942 inhibits heat transfer into conduit 512 fromferromagnetic sections 622. Limiting the heat transfer into conduit 512reduces heat loss and/or inhibits overheating of fluids in the conduit.In an embodiment, heater 534 provides heat along an entire length of theheater and conduit 512 includes conduit 942 along an entire length ofthe production conduit.

In certain embodiments, more than one wellbore 922 is used to produceheavy oils from a formation using the temperature limited heater. FIG.164 depicts an end view of an embodiment with wellbores 922 located inhydrocarbon layer 380. Portions of wellbores 922 are placedsubstantially horizontally in a triangular pattern in hydrocarbon layer380. In certain embodiments, wellbores 922 have a spacing of 30 m to 60m, 35 m to 55 m, or 40 m to 50 m. Wellbores 922 may include productionconduits and heaters previously described. Fluids may be heated andproduced through wellbores 922 at an increased production rate above acold production rate for the formation. Production may continue for aselected time (for example, 5 years to 10 years, 6 years to 9 years, or7 years to 8 years) until heat produced from each of wellbores 922begins to overlap (superposition of heat begins). At such a time, heatfrom lower wellbores (such as wellbores 922 near the bottom ofhydrocarbon layer 380) is continued, reduced, or turned off whileproduction is continued. Production in upper wellbores (such aswellbores 922 near the top of hydrocarbon layer 380) may be stopped sothat fluids in the hydrocarbon layer drain towards the lower wellbores.In some embodiments, power is increased to the upper wellbores and thetemperature raised above the Curie temperature to increase the heatinjection rate. Draining fluids in the formation in such a processincreases total hydrocarbon recovery from the formation.

In an embodiment, a temperature limited heater is used in a horizontalheater/production well. The temperature limited heater may provideselected amounts of heat to the “toe” and the “heel” of the horizontalportion of the well. More heat may be provided to the formation throughthe toe than through the heel, creating a “hot portion” at the toe and a“warm portion” at the heel. Formation fluids may be formed in the hotportion and produced through the warm portion, as shown in FIG. 165.

FIG. 165 depicts an embodiment of a heater well for selectively heatinga formation. Heat source 202 is placed in opening 378 in hydrocarbonlayer 380. In certain embodiments, opening 378 is a substantiallyhorizontal opening in hydrocarbon layer 380. Perforated casing 928 isplaced in opening 378. Perforated casing 928 provides support thatinhibits hydrocarbon and/or other material in hydrocarbon layer 380 fromcollapsing into opening 378. Perforations in perforated casing 928 allowfor fluid flow from hydrocarbon layer 380 into opening 378. Heat source202 may include hot portion 944. Hot portion 944 is a portion of heatsource 202 that operates at higher heat output than adjacent portions ofthe heat source. For example, hot portion 944 may output between 650 W/mand 1650 W/m, 650 W/m and 1500 W/m, or 800 W/m and 1500 W/m. Hot portion944 may extend from a “heel” of the heat source to the “toe” of the heatsource. The heel of the heat source is the portion of the heat sourceclosest to the point at which the heat source enters a hydrocarbonlayer. The toe of the heat source is the end of the heat source furthestfrom the entry of the heat source into a hydrocarbon layer.

In an embodiment, heat source 202 includes warm portion 946. Warmportion 946 is a portion of heat source 202 that operates at lower heatoutputs than hot portion 944. For example, warm portion 946 may outputbetween 30 W/m and 1000 W/m, 30 W/m and 750 W/m, or 100 W/m and 750 W/m.Warm portion 946 may be located closer to the heel of heat source 202.In certain embodiments, warm portion 946 is a transition portion (forexample, a transition conductor) between hot portion 944 and overburdenportion 948. Overburden portion 948 is located in overburden 382.Overburden portion 948 provides a lower heat output than warm portion946. For example, overburden portion 948 may output between 10 W/m and90 W/m, 15 W/m and 80 W/m, or 25 W/m and 75 W/m. In some embodiments,overburden portion 948 provides as close to no heat (0 W/m) as possibleto overburden 382. Some heat, however, may be used to maintain fluidsproduced through opening 378 in a vapor phase or at elevated temperaturein overburden 382.

In certain embodiments, hot portion 944 of heat source 202 heatshydrocarbons to high enough temperatures to result in coke 950 formingin hydrocarbon layer 380. Coke 950 may occur in an area surroundingopening 378. Warm portion 946 may be operated at lower heat outputs sothat coke does not form at or near the warm portion of heat source 202.Coke 950 may extend radially from opening 378 as heat from heat source202 transfers outward from the opening. At a certain distance, however,coke 950 no longer forms because temperatures in hydrocarbon layer 380at the certain distance will not reach coking temperatures. The distanceat which no coke forms is a function of heat output (W/m from heatsource 202), type of formation, hydrocarbon content in the formation,and/or other conditions in the formation.

The formation of coke 950 inhibits fluid flow into opening 378 throughthe coking. Fluids in the formation may, however, be produced throughopening 378 at the heel of heat source 202 (for example, at warm portion946 of the heat source) where there is little or no coke formation. Thelower temperatures at the heel of heat source 202 reduce the possibilityof increased cracking of formation fluids produced through the heel.Fluids may flow in a horizontal direction through the formation moreeasily than in a vertical direction. Typically, horizontal permeabilityin a relatively permeable formation is approximately 5 to 10 timesgreater than vertical permeability. Thus, fluids flow along the lengthof heat source 202 in a substantially horizontal direction. Producingformation fluids through opening 378 is possible at earlier times thanproducing fluids through production wells in hydrocarbon layer 380. Theearlier production times through opening 378 is possible becausetemperatures near the opening increase faster than temperatures furtheraway due to conduction of heat from heat source 202 through hydrocarbonlayer 380. Early production of formation fluids may be used to maintainlower pressures in hydrocarbon layer 380 during start-up heating of theformation. Start-up heating of the formation is the time of heatingbefore production begins at production wells in the formation. Lowerpressures in the formation may increase liquid production from theformation. In addition, producing formation fluids through opening 378may reduce the number of production wells needed in the formation.

In some embodiments, a temperature limited heater is used to heat asurface pipeline such as a sulfur transfer pipeline. For example, asurface sulfur pipeline may be heated to a temperature of about 100° C.,about 110° C., or about 130° C. to inhibit solidification of fluids inthe pipeline. Higher temperatures in the pipeline (for example, aboveabout 130° C.) may induce undesirable degradation of fluids in thepipeline.

In some embodiments, a temperature limited heater positioned in awellbore heats steam that is provided to the wellbore. The heated steammay be introduced into a portion of the formation. In certainembodiments, the heated steam may be used as a heat transfer fluid toheat a portion of the formation. In some embodiments, the steam is usedto solution mine desired minerals from the formation. In someembodiments, the temperature limited heater positioned in the wellboreheats liquid water that is introduced into a portion of the formation.

In an embodiment, the temperature limited heater includes ferromagneticmaterial with a selected Curie temperature. The use of a temperaturelimited heater may inhibit a temperature of the heater from increasingbeyond a maximum selected temperature (for example, at or about theCurie temperature). Limiting the temperature of the heater may inhibitpotential burnout of the heater. The maximum selected temperature may bea temperature selected to heat the steam to above or near 100%saturation conditions, superheated conditions, or supercriticalconditions. Using a temperature limited heater to heat the steam mayinhibit overheating of the steam in the wellbore. Steam introduced intoa formation may be used for synthesis gas production, to heat thehydrocarbon containing formation, to carry chemicals into the formation,to extract chemicals or minerals from the formation, and/or to controlheating of the formation.

A portion of the formation where steam is introduced or that is heatedwith steam may be at significant depths below the surface (for example,greater than about 1000 m, about 2500, or about 5000 m below thesurface). If steam is heated at the surface of the formation andintroduced to the formation through a wellbore, a quality of the heatedsteam provided to the wellbore at the surface may have to be relativelyhigh to accommodate heat losses to the wellbore casing and/or theoverburden as the steam travels down the wellbore. Heating the steam inthe wellbore may allow the quality of the steam to be significantlyimproved before the steam is provided to the formation. A temperaturelimited heater positioned in a lower section of the overburden and/oradjacent to a target zone of the formation may be used to controllablyheat steam to improve the quality of the steam injected into theformation and/or inhibit condensation along the length of the heater. Incertain embodiments, the temperature limited heater improves the qualityof the steam injected and/or inhibits condensation in the wellbore forlong steam injection wellbores (especially for long horizontal steaminjection wellbores).

A temperature limited heater positioned in a wellbore may be used toheat the steam to above or near 100% saturation conditions orsuperheated conditions. In some embodiments, a temperature limitedheater may heat the steam so that the steam is above or nearsupercritical conditions. The static head of fluid above the temperaturelimited heater may facilitate producing 100% saturation, superheated,and/or supercritical conditions in the steam. Supercritical or nearsupercritical steam may be used to strip hydrocarbon material and/orother materials from the formation. In certain embodiments, steamintroduced into the formation may have a high density (for example, aspecific gravity of about 0.8 or above). Increasing the density of thesteam may improve the ability of the steam to strip hydrocarbon materialand/or other materials from the formation.

Improved alloys containing manganese, copper and tungsten, incombination with niobium, carbon and nitrogen, may maintain a finergrain size despite high temperature solution annealing or processing.Such behavior may be beneficial in reducing a heat-affected-zone inwelded material. Higher solution-annealing temperatures are particularlyimportant for achieving the best NbC nano-carbide strengthening duringhigh-temperature creep service, and such effects are amplified (finernano-carbide structures that are stable) by compositions of the improvedalloys. Tubing and canister applications that include the composition ofthe improved alloys and are wrought processed result in stainless steelsthat may be able to age-harden during service at about 700° C. to about800° C. Improved alloys may be able to age-harden even more if thealloys are cold-strained prior to high-temperature service.Cold-prestraining may degrade rather than enhance high-temperaturestrength and long-term durability, and therefore may be limited or notpermitted by, for example, construction codes.

An improved alloy may include, by weight: about 18% to about 22%chromium, about 12% to about 13% nickel, above 0% to about 4.5% copper,about 1% to about 5% manganese, about 0.3% to about 1% silicon, above 0%to about 1% niobium, about 0.3% to about 1% molybdenum, about 0.08% toabout 0.2% carbon, about 0.2% to about 0.5% nitrogen, above 0% to about2% tungsten, and with the balance being iron (for example, about 47.8%to about 68.12% iron). Such an improved alloy may be useful whenprocessed by hot deformation, cold deformation, and/or welding into, forexample, casings, canisters, or strength members for heaters. In someembodiments, the improved alloy includes, by weight: about 20% chromium,about 3% copper, about 4% manganese, about 0.3% molybdenum, about 0.77%niobium, about 13% nickel, about 0.5% silicon, about 1% tungsten, about0.09% carbon, and about 0.26% nitrogen, with the balance being iron. Incertain embodiments, the improved alloy includes, by weight: about 19%chromium, about 4.2% manganese, about 0.3% molybdenum, about 0.8%niobium, about 12.5% nickel, about 0.5% silicon, about 0.09% carbon,about 0.24% nitrogen by weight with the balance being iron. In someembodiments, improved alloys may vary an amount of manganese, amount ofnickel, and/or a Mn/Ni ratio to enhance resistance to high temperaturesulfidation, increase high temperature strength, and/or reduce cost.

In some embodiments, the improved alloys are processed to produce awrought material. A 6″ inside diameter, centrifugal cast pipe having awall thickness of 1.5″ may be cast from the improved alloy. A sectionmay be removed from the casting and heat treated at least about 1250° C.for, for example, about three hours. The heat treated section may be hotrolled at least about 1200° C. to a 0.75″ thickness, annealed at leastabout 1200° C. for fifteen minutes, and then sandblasted. Thesandblasted section may be cold rolled to a thickness of about 0.55″.The cold rolled section may be annealed at least about 1250° C. forabout an hour in, for example, air with an argon cover, and then given afinal additional heat treatment for about one hour at least about 1250°C. in air with an argon cover. An alternative process may include any ofthe following: initially homogenizing the cast plate at least about1200° C. for about 1½ hours; hot rolling at least about 1200° C. to a 1″thickness; and annealing the cold-rolled plate for about one hour atleast about 1200° C.

The improved alloys may be extruded at, for example, about 1200° C.,with, for example, a mandrel diameter of 0.9″ and a die diameter of1.35″ to produce good quality tubes. The wrought material may be weldedby, for example, laser welding. Thus, tubes may be produced by rollingplates and welding seams.

Improved alloys may have high temperature creep strengths and tensilestrengths that are superior to conventional alloys. For example, niobiumstabilized stainless steel alloys that include manganese, nitrogen,copper and tungsten may have high temperature creep strengths andtensile strengths that are improved, or substantially improved relativeto conventional alloys such as 347H.

Improved alloys may have increased strength relative to standardstainless steel alloys such as Super 304H at high temperatures (forexample, about 700° C., about 800° C., or above 1000° C.). Superior hightemperature creep-rupture strength (for example, creep-rupture strengthat about 800° C., about 900° C. or about 1250° C.) may be improved as aresult of (a) composition, (b) stable, fine-grain microstructuresinduced by high temperature processing, and (c) age-inducedprecipitation structures in the improved alloys. Precipitationstructures include, for example, micro-carbides that strengthen grainboundaries and stable nano-carbides that strengthen inside the grains.Presence of phases other than sigma and laves phases contribute to hightemperature properties. Stable microstructures may be achieved by properselection of components. High temperature aging induced or creep-inducedmicrostructures have minimal or no intermetallic sigma and laves phases.Intermetallic sigma and lava phases may weaken the strength propertiesof alloys.

At about 800° C., the improved alloys may include at least 3% by weightof micro-carbides, other phases, and/or stable, fine grainmicrostructure that produce strength. At about 900° C., the improvedalloys may include at least 1.5% by weight, at least 2% by weight, atleast 3% by weight, at least 3.5% by weight, or at least 5% by weightmicro-carbides, other phases, and/or stable, fine grain microstructurethat produce strength. These values may be higher than the correspondingvalues in 347H or Super 304H stainless steel alloys at about 900° C. Atabout 1250° C. improved alloys may include at least 0.5% by weightmicro-carbides, other phases, and/or stable, fine grain microstructurethat produce strength. The resulting higher weight percent ofmicro-carbides, other phases, and/or stable, fine grain microstructure,and the exclusion of sigma and laves phases, may account for superiorhigh temperature performance of the improved alloys.

Alloys having similar or superior high temperature performance to theimproved alloys may be derived by modelling phase behaviour at elevatedtemperatures and selecting compositions that retain at least 1.5%, 2%,or 2.5% by weight of phases other than sigma or laves phases at, forexample, about 900° C. For example, a stable microstructure may includean amount of niobium that is nearly ten times the amount of carbon,along with 1% to 5% of manganese, and nitrogen. Copper and tungsten maybe included in the composition to increase the amount of stablemicrostructures. The choice of elements for the improved alloys allowsprocessing by various methods and results in a stable, fine grain size,even after heat treatments of at least about 1250° C. Many prior artalloys tend to grain coarsen significantly when annealed at such hightemperatures. In some embodiments, grain size is controlled to achievedesirable high temperature tensile and creep properties. Stable grainstructure in the improved alloys reduces grain boundary sliding, and maybe a contributing factor for the better strength relative tocommercially available alloys at temperatures above, for example, about650° C.

Non-Restrictive Examples are Set Forth Below.

FIGS. 166-183 depict experimental data for temperature limited heaters.FIG. 166 depicts electrical resistance (Ω) versus temperature (° C.) atvarious applied electrical currents for a 446 stainless steel rod with adiameter of 2.5 cm and a 410 stainless steel rod with a diameter of 2.5cm. Both rods had a length of 1.8 m. Curves 952-958 depict resistanceprofiles as a function of temperature for the 446 stainless steel rod at440 amps AC (curve 952), 450 amps AC (curve 954), 500 amps AC (curve956), and 10 amps DC (curve 958). Curves 960-966 depict resistanceprofiles as a function of temperature for the 410 stainless steel rod at400 amps AC (curve 960), 450 amps AC (curve 962), 500 amps AC (curve964), 10 amps DC (curve 966). For both rods, the resistance graduallyincreased with temperature until the Curie temperature was reached. Atthe Curie temperature, the resistance fell sharply. Above the Curietemperature, the resistance decreased slightly with increasingtemperature. Both rods show a trend of decreasing resistance withincreasing AC current. Accordingly, the turndown ratio decreased withincreasing current. Thus, the rods provide a reduced amount of heat nearand above the Curie temperature of the rods. In contrast, the resistancegradually increased with temperature through the Curie temperature withthe applied DC current.

FIG. 167 shows electrical resistance (Ω) profiles as a function oftemperature (° C.) at various applied electrical currents for a copperrod contained in a conduit of Sumitomo HCM12A (a high strength 410stainless steel). The Sumitomo conduit had a diameter of 5.1 cm, alength of 1.8 m, and a wall thickness of about 0.1 cm. Curves 968-978show that at all applied currents (968: 300 amps AC; 970: 350 amps AC;972: 400 alps AC; 974: 450 amps AC; 976: 500 amps AC; 978: 550 amps AC),resistance increased gradually with temperature until the Curietemperature was reached. At the Curie temperature, the resistance fellsharply. As the current increased, the resistance decreased, resultingin a smaller turndown ratio.

FIG. 168 depicts electrical resistance (Ω) versus temperature (° C.) atvarious applied electrical currents for a temperature limited heater.The temperature limited heater included a 4/0 MGT-1000 furnace cableinside an outer conductor of ¾″ Schedule 80 Sandvik (Sweden) 4C54 (446stainless steel) with a 0.30 cm thick copper sheath welded onto theoutside of the Sandvik 4C54 and a length of 1.8 m. Curves 980 through998 show resistance profiles as a function of temperature for AC appliedcurrents ranging from 40 amps to 500 amps (980: 40 amps; 982: 80 amps;984: 120 amps; 986: 160 amps; 988: 250 amps; 990: 300 amps; 992: 350amps; 994: 400 amps; 996: 450 amps; 998: 500 amps). FIG. 169 depicts theraw data for curve 994. FIG. 170 depicts the data for selected curves990, 992, 994, 996, 998, and 1000. At lower currents (below 250 amps),the resistance increased with increasing temperature up to the Curietemperature. At the Curie temperature, the resistance fell sharply. Athigher currents (above 250 amps), the resistance decreased slightly withincreasing temperature up to the Curie temperature. At the Curietemperature, the resistance fell sharply. Curve 1000 shows resistancefor an applied DC electrical current of 10 amps. Curve 1000 shows asteady increase in resistance with increasing temperature, with littleor no deviation at the Curie temperature.

FIG. 171 depicts power (watts per meter (W/m)) versus temperature (° C.)at various applied electrical currents for a temperature limited heater.The temperature limited heater included a 4/0 MGT-1000 furnace cableinside an outer conductor of ¾″ Schedule 80 Sandvik (Sweden) 4C54 (446stainless steel) with a 0.30 cm thick copper sheath welded onto theoutside of the Sandvik 4C54 and a length of 1.8 m. Curves 1002-1010depict power versus temperature for AC applied currents of 300 amps to500 amps (1002: 300 amps; 1004: 350 amps; 1006: 400 amps; 1008: 450amps; 1010: 500 amps). Increasing the temperature gradually decreasedthe power until the Curie temperature was reached. At the Curietemperature, the power decreased rapidly.

FIG. 172 depicts electrical resistance (mΩ) versus temperature (° C.) atvarious applied electrical currents for a temperature limited heater.The temperature limited heater included a copper rod with a diameter of1.3 cm inside an outer conductor of 2.5 cm Schedule 80 410 stainlesssteel pipe with a 0.15 cm thick copper Everdur™ (DuPont Engineering,Wilmington, Del., U.S.A.) welded sheath over the 410 stainless steelpipe and a length of 1.8 m. Curves 1012-1022 show resistance profiles asa function of temperature for AC applied currents ranging from 300 ampsto 550 amps (1012: 300 amps; 1014: 350 amps; 1016: 400 amps; 1018: 450amps; 1020: 500 amps; 1022: 550 amps). For these AC applied currents,the resistance gradually increases with increasing temperature up to theCurie temperature. At the Curie temperature, the resistance fallssharply. In contrast, curve 1024 shows resistance for an applied DCelectrical current of 10 amps. This resistance shows a steady increasewith increasing temperature, and little or no deviation at the Curietemperature.

FIG. 173 depicts data of electrical resistance (mΩ) versus temperature(° C.) for a solid 2.54 cm diameter, 1.8 m long 410 stainless steel rodat various applied electrical currents. Curves 1026, 1028, 1030, 1032,and 1034 depict resistance profiles as a function of temperature for the410 stainless steel rod at 40 amps AC (curve 1032), 70 amps AC (curve1034), 140 amps AC (curve 1026), 230 amps AC (curve 1028), and 10 ampsDC (curve 1030). For the applied AC currents of 140 amps and 230 amps,the resistance increased gradually with increasing temperature until theCurie temperature was reached. At the Curie temperature, the resistancefell sharply. In contrast, the resistance showed a gradual increase withtemperature through the Curie temperature for the applied DC current.

FIG. 174 depicts data of electrical resistance (mΩ) versus temperature(° C.) for a composite 1.75 inch (1.9) diameter, 6 foot (1.8 m) longAlloy 42-6 rod with a 0.375 inch diameter copper core (the rod has anoutside diameter to copper diameter ratio of 2:1) at various appliedelectrical currents. Curves 1036, 1038, 1040, 1042, 1044, 1046, 1048,and 1050 depict resistance profiles as a function of temperature for thecopper cored alloy 42-6 rod at 300 A AC (curve 1036), 350 A AC (curve1038), 400 A AC (curve 1040), 450 A AC (curve 1042), 500 A AC (curve1044), 550 A AC (curve 1046), 600 A AC (curve 1048), and 10 A DC (curve1050). For the applied AC currents, the resistance decreased graduallywith increasing temperature until the Curie temperature was reached. Asthe temperature approaches the Curie temperature, the resistancedecreased more sharply. In contrast, the resistance showed a gradualincrease with temperature for the applied DC current.

FIG. 175 depicts data of power output (watts per foot (W/ft)) versustemperature (° C.) for a composite 1.75 inch (1.9 cm) diameter, 6 foot(1.8 m) long Alloy 42-6 rod with a 0.375 inch diameter copper core (therod has an outside diameter to copper diameter ratio of 2:1) at variousapplied electrical currents. Curves 1052, 1054, 1056, 1058, 1060, 1062,1064, and 1066 depict power as a function of temperature for the coppercored alloy 42-6 rod at 300 A AC (curve 1052), 350 A AC (curve 1054),400 A AC (curve 1056), 450 A AC (curve 1058), 500 A AC (curve 1060), 550A AC (curve 1062), 600 A AC (curve 1064), and 10 A DC (curve 1066). Forthe applied AC currents, the power output decreased gradually withincreasing temperature until the Curie temperature was reached. As thetemperature approaches the Curie temperature, the power output decreasedmore sharply. In contrast, the power output showed a relatively flatprofile with temperature for the applied DC current.

FIG. 176 depicts data of electrical resistance (mΩ) versus temperature(° C.) for a composite 0.75″ diameter, 6 foot long Alloy 52 rod with a0.375″ diameter copper core at various applied electrical currents.Curves 1068, 1070, 1072, 1074, and 1076 depict resistance profiles as afunction of temperature for the copper cored Alloy 52 rod at 300 A AC(curve 1068), 400 A AC (curve 1070), 500 A AC (curve 1072), 600 A AC(curve 1074), and 10 A DC (curve 1076). For the applied AC currents, theresistance increased gradually with increasing temperature until around320° C. After 320° C., the resistance began to decrease gradually,decreasing more sharply as the temperature approached the Curietemperature. At the Curie temperature, the AC resistance decreased verysharply. In contrast, the resistance showed a gradual increase withtemperature for the applied DC current. The turndown ratio for the 400 Aapplied AC current (curve 1070) was 2.8.

FIG. 177 depicts data of power output (watts per foot (W/ft)) versustemperature (° C.) for a composite 1.75″ diameter, 6 foot long Alloy 52rod with a 0.375″ diameter copper core at various applied electricalcurrents. Curves 1078, 1080, 1082, and 1084 depict power as a functionof temperature for the copper cored Alloy 52 rod at 300 A AC (curve1078), 400 A AC (curve 1080), 500 A AC (curve 1082), and 600 A AC (curve1084). For the applied AC currents, the power output increased graduallywith increasing temperature until around 320° C. After 320° C., thepower output began to decrease gradually, decreasing more sharply as thetemperature approached the Curie temperature. At the Curie temperature,the power output decreased very sharply.

FIG. 178 depicts data for values of skin depth (cm) versus temperature(° C.) for a solid 2.54 cm diameter, 1.8 m long 410 stainless steel rodat various applied AC electrical currents. The skin depth was calculatedusing EQN. 6:δ=R ₁ −R ₁×(1−(1/R _(AC) /R _(DC)))^(1/2);  (6)where 6 is the skin depth, R₁ is the radius of the cylinder, R_(AC) isthe AC resistance, and R_(DC) is the DC resistance. In FIG. 178, curves1086-1104 show skin depth profiles as a function of temperature forapplied AC electrical currents over a range of 50 amps to 500 amps(1086: 50 amps; 1088: 100 amps; 1090: 150 amps; 1092: 200 amps; 1094:250 amps; 1096: 300 amps; 1098: 350 amps; 1100: 400 amps; 1102: 450amps; 1104: 500 amps). For each applied AC electrical current, the skindepth gradually increased with increasing temperature up to the Curietemperature. At the Curie temperature, the skin depth increased sharply.

FIG. 179 depicts temperature (° C.) versus time (hrs) for a temperaturelimited heater. The temperature limited heater was a 1.83 m long heaterthat included a copper rod with a diameter of 1.3 cm inside a 2.5 cmSchedule XXH 410 stainless steel pipe and a 0.325 cm copper sheath. Theheater was placed in an oven for heating. Alternating current wasapplied to the heater when the heater was in the oven. The current wasincreased over two hours and reached a relatively constant value of 400amps for the remainder of the time. Temperature of the stainless steelpipe was measured at three points at 0.46 m intervals along the lengthof the heater. Curve 1106 depicts the temperature of the pipe at a point0.46 m inside the oven and closest to the lead-in portion of the heater.Curve 1108 depicts the temperature of the pipe at a point 0.46 m fromthe end of the pipe and furthest from the lead-in portion of the heater.Curve 1110 depicts the temperature of the pipe at about a center pointof the heater. The point at the center of the heater was furtherenclosed in a 0.3 m section of 2.5 cm thick Fiberfrax® (Unifrax Corp.,Niagara Falls, N.Y., U.S.A.) insulation. The insulation was used tocreate a low thermal conductivity section on the heater (a section whereheat transfer to the surroundings is slowed or inhibited (a “hotspot”)). The temperature of the heater increased with time as shown bycurves 1110, 1108, and 1106. Curves 1110, 1108, and 1106 show that thetemperature of the heater increased to about the same value for allthree points along the length of the heater. The resulting temperatureswere substantially independent of the added Fiberfrax® insulation. Thus,the operating temperatures of the temperature limited heater weresubstantially the same despite the differences in thermal load (due tothe insulation) at each of the three points along the length of theheater. Thus, the temperature limited heater did not exceed the selectedtemperature limit in the presence of a low thermal conductivity section.

FIG. 180 depicts temperature (° C.) versus log time (hrs) data for a 2.5cm solid 410 stainless steel rod and a 2.5 cm solid 304 stainless steelrod. At a constant applied AC electrical current, the temperature ofeach rod increased with time. Curve 1112 shows data for a thermocoupleplaced on an outer surface of the 304 stainless steel rod and under alayer of insulation. Curve 1114 shows data for a thermocouple placed onan outer surface of the 304 stainless steel rod without a layer ofinsulation. Curve 1116 shows data for a thermocouple placed on an outersurface of the 410 stainless steel rod and under a layer of insulation.Curve 1118 shows data for a thermocouple placed on an outer surface ofthe 410 stainless steel rod without a layer of insulation. A comparisonof the curves shows that the temperature of the 304 stainless steel rod(curves 1112 and 1114) increased more rapidly than the temperature ofthe 410 stainless steel rod (curves 1116 and 1118). The temperature ofthe 304 stainless steel rod (curves 1112 and 1114) also reached a highervalue than the temperature of the 410 stainless steel rod (curves 1116and 1118). The temperature difference between the non-insulated sectionof the 410 stainless steel rod (curve 1118) and the insulated section ofthe 410 stainless steel rod (curve 1116) was less than the temperaturedifference between the non-insulated section of the 304 stainless steelrod (curve 1114) and the insulated section of the 304 stainless steelrod (curve 1112). The temperature of the 304 stainless steel rod wasincreasing at the termination of the experiment (curves 1112 and 1114)while the temperature of the 410 stainless steel rod had leveled out(curves 1116 and 1118). Thus, the 410 stainless steel rod (thetemperature limited heater) provided better temperature control than the304 stainless steel rod (the non-temperature limited heater) in thepresence of varying thermal loads (due to the insulation).

A 6 foot temperature limited heater element was placed in a 6 foot 347Hstainless steel canister. The heater element was connected to thecanister in a series configuration. The heater element and canister wereplaced in an oven. The oven was used to raise the temperature of theheater element and the canister. At varying temperatures, a series ofelectrical currents were passed through the heater element and returnedthrough the canister. The resistance of the heater element and the powerfactor of the heater element were determined from measurements duringpassing of the electrical currents.

FIG. 181 depicts experimentally measured electrical resistance (mΩ)versus temperature (° C.) at several currents for a temperature limitedheater with a copper core, a carbon steel ferromagnetic conductor, and a347H stainless steel support member. The ferromagnetic conductor was alow-carbon steel with a Curie temperature of 770° C. The ferromagneticconductor was sandwiched between the copper core and the 347H supportmember. The copper core had a diameter of 0.5″. The ferromagneticconductor had an outside diameter of 0.765″. The support member had anoutside diameter of 1.05″. The canister was a 3″ Schedule 160 347Hstainless steel canister.

Data 1120 depicts electrical resistance versus temperature for 300 A at60 Hz AC applied current. Data 1122 depicts resistance versustemperature for 400 A at 60 Hz AC applied current. Data 1124 depictsresistance versus temperature for 500 A at 60 Hz AC applied current.Curve 1126 depicts resistance versus temperature for 10 A DC appliedcurrent. The resistance versus temperature data indicates that the ACresistance of the temperature limited heater linearly increased up to atemperature near the Curie temperature of the ferromagnetic conductor.Near the Curie temperature, the AC resistance decreased rapidly untilthe AC resistance equaled the DC resistance above the Curie temperature.The linear dependence of the AC resistance below the Curie temperatureat least partially reflects the linear dependence of the AC resistanceof 347H at these temperatures. Thus, the linear dependence of the ACresistance below the Curie temperature indicates that the majority ofthe current is flowing through the 347H support member at thesetemperatures.

FIG. 182 depicts experimentally measured electrical resistance (mΩ)versus temperature (° C.) data at several currents for a temperaturelimited heater with a copper core, a iron-cobalt ferromagneticconductor, and a 347H stainless steel support member. The iron-cobaltferromagnetic conductor was an iron-cobalt conductor with 6% cobalt byweight and a Curie temperature of 834° C. The ferromagnetic conductorwas sandwiched between the copper core and the 347H support member. Thecopper core had a diameter of 0.465″. The ferromagnetic conductor had anoutside diameter of 0.765″. The support member had an outside diameterof 1.05″. The canister was a 3″ Schedule 160 347H stainless steelcanister.

Data 1128 depicts resistance versus temperature for 100 A at 60 Hz ACapplied current. Data 1130 depicts resistance versus temperature for 400A at 60 Hz AC applied current. Curve 1132 depicts resistance versustemperature for 10 A DC. The AC resistance of this temperature limitedheater turned down at a higher temperature than the previous temperaturelimited heater. This was due to the added cobalt increasing the Curietemperature of the ferromagnetic conductor. The AC resistance wassubstantially the same as the AC resistance of a tube of 347H steelhaving the dimensions of the support member. This indicates that themajority of the current is flowing through the 347H support member atthese temperatures. The resistance curves in FIG. 182 are generally thesame shape as the resistance curves in FIG. 181.

FIG. 183 depicts experimentally measured power factor (y-axis) versustemperature (° C.) at two AC currents for the temperature limited heaterwith the copper core, the iron-cobalt ferromagnetic conductor, and the347H stainless steel support member. Curve 1134 depicts power factorversus temperature for 100 A at 60 Hz AC applied current. Curve 1136depicts power factor versus temperature for 400 A at 60 Hz AC appliedcurrent. The power factor was close to unity (1) except for the regionaround the Curie temperature. In the region around the Curietemperature, the non-linear magnetic properties and a larger portion ofthe current flowing through the ferromagnetic conductor produceinductive effects and distortion in the heater that lowers the powerfactor. FIG. 183 shows that the minimum value of the power factor forthis heater remained above 0.85 at all temperatures in the experiment.Because only portions of the temperature limited heater used to heat asubsurface formation may be at the Curie temperature at any given pointin time and the power factor for these portions does not go below 0.85during use, the power factor for the entire temperature limited heaterwould remain above 0.85 (for example, above 0.9 or above 0.95) duringuse.

From the data in the experiments for the temperature limited heater withthe copper core, the iron-cobalt ferromagnetic conductor, and the 347Hstainless steel support member, the turndown ratio (y-axis) wascalculated as a function of the maximum power (W/m) delivered by thetemperature limited heater. The results of these calculations aredepicted in FIG. 184. The curve in FIG. 184 shows that the turndownratio (y-axis) remains above 2 for heater powers up to approximately2000 W/m. This curve is used to determine the ability of a heater toeffectively provide heat output in a sustainable manner. A temperaturelimited heater with the curve similar to the curve in FIG. 184 would beable to provide sufficient heat output while maintaining temperaturelimiting properties that inhibit the heater from overheating ormalfunctioning.

A theoretical model has been used to predict the experimental results.The theoretical model is based on an analytical solution for the ACresistance of a composite conductor. The composite conductor has a thinlayer of ferromagnetic material, with a relative magnetic permeabilityμ₂μ₀>>1, sandwiched between two non-ferromagnetic materials, whoserelative magnetic permeabilities, μ₁/μ₀ and μ₃/μ₀ are close to unity andwithin which skin effects are negligible. An assumption in the model isthat the ferromagnetic material is treated as linear. In addition, theway in which the relative magnetic permeability, μ₂μ₀, is extracted frommagnetic data for use in the model is far from rigorous.

In the theoretical model, the three conductors, from innermost tooutermost, have radii a<b<c with electrical conductivities σ₁, σ₂, andσ₃, respectively. The electric and magnetic fields everywhere are of theharmonic form:

Electric Fields:E ₁(r,t)=E _(S1)(r)e ^(jωt) ; r<a;  (7)E ₂(r,t)=E _(S2)(r)e ^(jωt) ; a<r<b; and  (8)E ₃(r,t)=E _(S3)(r)e ^(jωt) ; b<r<c.  (9)Magnetic Fields:H ₁(r,t)=H _(S1)(r)e ^(jωt) ; r<a;  (10)H ₂(r,t)=H _(S2)(r)e ^(jωt) a<r<b; and  (11)H ₃(r,t)=H _(S3)(r)e ^(jωt) ; b<r<c.  (12)

The boundary conditions satisfied at the interfaces are:E _(S1)(a)=E _(S2)(a); H _(S1)(a)=H _(S2)(a); and  (13)E _(S2)(b)=E _(S3)(b); H _(S2)(b)=H _(S3)(b).  (14)

Current flows uniformly in the non-Curie conductors, so that:H _(S1)(a)=J _(S1)(a)(a/2)=½aσ ₁ E _(S1)(a); and  (15)I−2πbH _(S3)(b)=π(c ² −b ²)J _(S3)(b)=π(c ² −b ²)σ₃ E _(S3)(b).  (16)

I denotes the total current flowing through the composite conductorsample. EQNS. 13 and 14 are used to express EQNS. 15 and 16 in terms ofboundary conditions pertaining to material 2 (the ferromagneticmaterial). This yields:H _(S2)(a)=½aσ ₁ E _(S2)(a); and  (17)I=2πbH _(S2)(b)+π(c ² −b ²)σ₃ E _(S2)(b)  (18)

E_(S2)(r) satisfies the equation:

$\begin{matrix}{{{{\frac{1}{r}\frac{\mathbb{d}}{\mathbb{d}r}\left( {r\frac{\mathbb{d}E_{S\; 2}}{\mathbb{d}r}} \right)} - {C^{2}E_{S\; 2}}} = 0},} & (19)\end{matrix}$

withC ² =jωμ ₂σ₂.  (20)

Using the fact that:

$\begin{matrix}{{{H_{S\; 2}(r)} = {\frac{j}{\mu_{2}\omega}\frac{\mathbb{d}E_{S\; 2}}{\mathbb{d}r}}};} & (21)\end{matrix}$the boundary conditions in EQNS. 17 and 18 are expressed in terms ofE_(S2) and its derivatives as follows:

$\begin{matrix}{{{{{\frac{j}{\mu_{2}\omega}\frac{\mathbb{d}E_{S\; 2}}{\mathbb{d}r}}❘_{a}} = {\frac{1}{2}a\;\sigma_{1}{E_{S\; 2}(a)}}};}{and}} & (22) \\{I = {{2\;\pi\; b\frac{j}{\mu_{2}\omega}\frac{\mathbb{d}E_{S\; 2}}{\mathbb{d}r}}❘_{b}{{+ {\pi\left( {c^{2} - b^{2}} \right)}}\sigma_{3}{{E_{S\; 2}(b)}.}}}} & (23)\end{matrix}$

The non-dimensional coordinate, X, is introduced via the equation:

$\begin{matrix}{r = {\frac{1}{2}\left( {a + b} \right){\left\{ {1 + {\frac{b - a}{a + b}\chi}} \right\}.}}} & (24)\end{matrix}$

χ is −1 for r=a, and χ is 1 for r=b. EQN. 19 is written in terms of χas:

$\begin{matrix}{{{{\left( {1 + {\beta\chi}} \right)^{- 1}\frac{\mathbb{d}}{\mathbb{d}\chi}\left\{ {\left( {1 + {\beta\chi}} \right)\frac{\mathbb{d}E_{S\; 2}}{\mathbb{d}\chi}} \right\}} - {\alpha^{2}\chi}} = 0},} & (25)\end{matrix}$

withα=½(b−a)C; and  (26)β=(b−a)/(b+a).  (27)

α can be expressed as:α=α_(R)(1−i),  (28)withα_(R) ²=⅛(b−a)²μ₂σ₂ω=¼(b−a)²/δ².  (29)

EQNS. 22 and 23 are expressed as:

$\begin{matrix}{{{{\frac{\mathbb{d}}{\mathbb{d}\chi}❘_{- 1}E_{a}} = {{- j}\;\gamma_{a}E_{a}}};}{and}} & (30) \\{{\frac{\mathbb{d}}{\mathbb{d}\chi}❘_{1}E_{b}} = {{j\;\gamma_{b}E_{b}} - {j{\overset{\sim}{I}.}}}} & (31)\end{matrix}$

In EQNS. 30 and 31, the short-hand notation E_(a) and E_(b) is used forE_(S2)(a) and E_(S2)(b), respectively, and the dimensionless parametersγ_(a) and γ_(b) and normalized current Ĩ have been introduced. Thesequantities are given by:γ_(a)=¼a(b−a)ωμ₂σ₁; γ_(b)=½(c ² −b ²)(b−a)ωμ₂σ₃ /b; and  (32)Ĩ=½(b−a)ωμ₂ I/(2πb).  (33)

EQN. 32 can be expressed in terms of dimensionless parameters by usingEQN. 29. The results are:γ_(a)=2(σ₁/σ₂)aα _(R) ²/(b−a); γ_(b)=4(σ₃/σ₂)(c ² −b ²)α_(R) ²/{b(b−a)}.  (34)

An alternative way of writing EQN. 34 is:γ_(a)=(σ₁/σ₂)aα _(R)/δ; γ_(b)=2(σ₃/σ₂)(c ² −b ²)α_(R)/(δb).  (35)

The mean power per unit length generated in the material is given by:

$\begin{matrix}{P = {{\frac{1}{2}\left\{ {{\sigma_{1}\pi\; a^{2}{E_{a}}^{2}} + {2{\pi\sigma}_{2}{\int_{a}^{b}\ {{\mathbb{d}{rr}}{{E_{S\; 2}(r)}}^{2}}}} + {\sigma_{3}{\pi\left( {c^{2} - b^{2}} \right)}{E_{b}}^{2}}} \right\}} = {\frac{1}{2}{\left\{ {{\sigma_{1}\pi\; a^{2}{E_{a}}^{2}} + {\frac{1}{2}{\pi\left( {b^{2} - a^{2}} \right)}\sigma_{2}{\int_{- 1}^{1}\ {{\mathbb{d}\chi}\left\{ {1 + {\beta\chi}} \right\}{{E_{S\; 2}(r)}}^{2}}}} + {\sigma_{3}{\pi\left( {c^{2} - b^{2}} \right)}{E_{b}}^{2}}} \right\}.}}}} & (36)\end{matrix}$

The AC resistance is then:R _(AC) =P/(½|I| ²).  (37)

To obtain an approximate solution of EQN. 25, β is assumed to be smallenough to be neglected in EQN. 25. This assumption holds if thethickness of the ferromagnetic material (material 2) is much less thanits mean radius. The general solution then takes the form:E _(S2) =Ae ^(αx) +Be ^(−αx).  (38)Then:E _(a) =Ae ^(−α) +Be ^(α); and  (39)E _(b) =Ae ^(α) +Be ^(−α).  (40)

Substituting EQNS. 38-40 into EQNS. 30 and 31 yields the following setof equations for A and B:α(Ae ^(−α) −Be ^(α))=−jγ _(a)(Ae ^(−α) +Be ^(α)); and  (41)α(Ae ^(α) −Be ^(−α))=jγ _(b)(Ae ^(α) +Be ^(−α))−jĨ.  (42)

Rearranging EQN. 41 obtains an expression for B in terms of A:

$\begin{matrix}{B = {\frac{\alpha + {j\;\gamma_{a}}}{\alpha - {j\;\gamma_{a}}}{\mathbb{e}}^{{- 2}\;\alpha}{A.}}} & (43)\end{matrix}$

This may be written as:

$\begin{matrix}{{B = {\frac{\alpha_{R} - {i\;\gamma_{a}^{+}}}{\alpha_{R} + {i\;\gamma_{a}^{-}}}{\mathbb{e}}^{{{- 2}\alpha_{R}} + {2\; i\;\alpha_{R}}}A}},} & (44)\end{matrix}$

withγ_(a) ^(±)=γ_(a)±α_(R).  (45)IfA=|A|exp(iφ _(A))  (46)and everything is referred back to the phase of A, then:φ_(A)=0.  (47)

From EQN. 44:B=|B|exp(iφ _(B)), with  (48)|B|=(Γ₊/Γ⁻)exp(−2α_(R))|A|; and  (49)φ_(B)=2α_(R)−φ₊−φ⁻; where  (50)Γ_(±)={α_(R) ²+(γ_(a) ^(±))²}^(0.5); and  (51)φ_(±)=tan⁻¹{φ_(±)/α_(R)}.  (52)Then:E _(a) =|A|exp(−α_(R) +iα _(R))+|B|exp{α_(R) +i(φ_(B)−α_(R))}; and  (53)E _(b) =|A|exp(α_(R) −iα _(R))+|B|exp{−α_(R) +i(φ_(B)+α_(R))}.  (54)Hence:Re[E _(a)]=|A|exp(−α_(R))cos(α_(R))+|B|exp(α_(R))cos(φ_(B)−α_(R));  (55A)Im[E _(a)]=|A|exp(−α_(R))sin(α_(R))+|B|exp(α_(R))sin(φ_(B)−α_(R));  (55B)Re[E _(b) ]=|A|exp(α_(R))cos(α_(R))+|B|exp(−α_(R))cos(φ_(B)+α_(R));and  (55C)Im[E _(a)]=−|A|exp(α_(R))sin(α_(R))+|B|exp(−α_(R))sin(φ_(B)+α_(R)).  (55D)

The ratio of absolute values of currents flowing through the center andouter conductors is then given by:

$\begin{matrix}{\frac{I_{1}}{I_{3}} = {\frac{a^{2}\sigma_{1}}{\left( {c^{2} - b^{2}} \right)\sigma_{3}}{\sqrt{\frac{{{Re}^{2}\left\lbrack E_{a} \right\rbrack} + {{Im}^{2}\left\lbrack E_{a} \right\rbrack}}{{{Re}^{2}\left\lbrack E_{b} \right\rbrack} + {{Im}^{2}\left\lbrack E_{b} \right\rbrack}}}.}}} & (56)\end{matrix}$

The total current flowing through the center conductor is given by:I ₂=δ₂π(b ² −a ²)(A+B)sin h(α)/α.  (57)Now:sin h(α)/α=(1+i){sin h(α_(R))cos(α_(R))−i cosh(α_(R))sin(α_(R))}/(2α_(R))=(S ⁺ +S ⁻ i), with  (58)S ^(±)={sin h(α_(R))cos(α_(R))±cos h(α_(R))sin(α_(R))}/(4α_(R)).  (59)Hence:Re[I ₂]=δ₂π(b ² −a ²){{|A|+|B|cos(φ_(B))}S ⁺ −|B|sin(φ_(B))S ⁻};and  (60)Im[I ₂]=σ₂π(b ² −a ²){{|A|+|B|cos(φ_(B))}S ⁻ +|B|sin(φ_(B))S ⁺}.  (61)

Root-mean-square current is therefore given by:I _(rms) ²=½{(Re[I ₁ ]+Re[I ₂ ]+Re[I ₃])²+(Im[I ₁ ]+Im[I ₂ ]+Im[I₂])²}.  (62)

Furthermore, EQNS. 40-42 are used to evaluate the second term on theright-hand side of EQN. 29 (neglecting the term in β). The result is:P=½{σ₁ πa ² |E _(a)|²+π(c ² −b ²)σ₃ |E _(b)|²+π(b ² −a ²)σ₂└(|A| ² +|B²|)sinh(2α_(R))/(2α_(R))+2|A∥B|sin(φ_(B)+2α_(R))/(φ_(B)+2α_(R))┘}.  (63)

Dividing EQN. 63 by EQN. 62 yields an expression for the AC resistance(cf. EQN. 37).

Given values for the dimensions a, b and c, and δ₁, σ₂ and σ₃, which areknown functions of temperature, and assuming a value for the relativemagnetic permeability of the ferromagnetic material (material 2), orequivalently, the skin depth δ, A=1 can be set and the AC resistance perunit length R_(AC) can be calculated. The ratio of the root-mean squarecurrent flowing through the inner conductor (material 1) and theferromagnetic material (material 2) to the total can also be calculated.For a given total RMS current, then, the RMS current flowing throughmaterials 1 and 2 can be calculated, which gives the magnetic field atthe surface of material 2. Using magnetic data for material 2, a valuefor μ₂/μ₀ can be deduced and hence a value for δ can be deduced.Plotting this skin depth against the original skin depth produces a pairof curves that cross at the true δ.

Magnetic data was obtained for carbon steel as a ferromagnetic material.B versus H curves, and hence relative permeabilities, were obtained fromthe magnetic data at various temperatures up to 1100° F. and magneticfields up to 200 Oe (oersteds). A correlation was found that fitted thedata well through the maximum permeability and beyond. FIG. 185 depictsexamples of relative magnetic permeability (y-axis) versus magneticfield (Oe) for both the found correlations and raw data for carbonsteel. Data 1138 is raw data for carbon steel at 400° F. Data 1140 israw data for carbon steel at 1000° F. Curve 1142 is the foundcorrelation for carbon steel at 400° F. Curve 1144 is the foundcorrelation for carbon steel at 1000° F.

For the dimensions and materials of the copper/carbon steel/347H heaterelement in the experiments above, the theoretical calculations describedabove were carried out to calculate magnetic field at the outer surfaceof the carbon steel as a function of skin depth. Results of thetheoretical calculations were presented on the same plot as skin depthversus magnetic field from the correlations applied to the magnetic datafrom FIG. 185. The theoretical calculations and correlations were madefor four temperatures (200° F., 500° F., 800° F., and 1100° F.) and fivetotal root-mean-square (RMS) currents (100 A, 200 A, 300 A, 400 A, and500 A).

FIG. 186 shows the resulting plots of skin depth (in) versus magneticfield (Oe) for all four temperatures and 400 A current. Curve 1146 isthe correlation from magnetic data at 200° F. Curve 1148 is thecorrelation from magnetic data at 500° F. Curve 1150 is the correlationfrom magnetic data at 800° F. Curve 1152 is the correlation frommagnetic data at 1100° F. Curve 1154 is the theoretical calculation atthe outer surface of the carbon steel as a function of skin depth at200° F. Curve 1156 is the theoretical calculation at the outer surfaceof the carbon steel as a function of skin depth at 500° F. Curve 1158 isthe theoretical calculation at the outer surface of the carbon steel asa function of skin depth at 800° F. Curve 1160 is the theoreticalcalculation at the outer surface of the carbon steel as a function ofskin depth at 1100° F.

The skin depths obtained from the intersections of the same temperaturecurves in FIG. 186 were input into the equations described above and theAC resistance per unit length was calculated. The total AC resistance ofthe entire heater, including that of the canister, was subsequentlycalculated. A comparison between the experimental and numerical(calculated) results is shown in FIG. 187 for currents of 300 A(experimental data 1162 and numerical curve 1164), 400 A (experimentaldata 1166 and numerical curve 1168), and 500 A (experimental data 1170and numerical curve 1172). Though the numerical results exhibit asteeper trend than the experimental results, the theoretical modelcaptures the close bunching of the experimental data, and the overallvalues are quite reasonable given the assumptions involved in thetheoretical model. For example, one assumption involved the use of apermeability derived from a quasistatic B-H curve to treat a dynamicsystem.

One feature of the theoretical model describing the flow of alternatingcurrent in the three-part temperature limited heater is that the ACresistance does not fall off monotonically with increasing skin depth.FIG. 188 shows the AC resistance (mΩ) per foot of the heater element asa function of skin depth (in.) at 1100° F. calculated from thetheoretical model. The AC resistance may be maximized by selecting theskin depth that is at the peak of the non-monotonical portion of theresistance versus skin depth profile (for example, at about 0.23 in. inFIG. 188).

FIG. 189 shows the power generated per unit length (W/ft) in each heatercomponent (curve 1174 (copper core), curve 1176 (carbon steel), curve1178 (347H outer layer), and curve 1180 (total)) versus skin depth(in.). As expected, the power dissipation in the 347H falls off whilethe power dissipation in the copper core increases as the skin depthincreases. The maximum power dissipation in the carbon steel occurs atthe skin depth of about 0.23 inches and is expected to correspond to theminimum in the power factor, as shown in FIG. 183. The current densityin the carbon steel behaves like a damped wave of wavelength λ=2πδ andthe effect of this wavelength on the boundary conditions at thecopper/carbon steel and carbon steel/347H interface may be behind thestructure in FIG. 188. For example, the local minimum in AC resistanceis close to the value at which the thickness of the carbon steel layercorresponds to λ/4.

Formulae may be developed that describe the shapes of the AC resistanceversus temperature profiles of temperature limited heaters for use insimulating the performance of the heaters in a particular embodiment.The data in FIGS. 181 and 182 show that the resistances initially riselinearly, then drop off increasingly steeply towards the DC lines. Theresistance versus temperature profile of each heater can be describedby:R _(AC) =A _(AC) +B _(AC) T; T<<T _(C); and  (64)R _(AC) =R _(DC) =A _(DC) +B _(DC) T; T>>T _(C).  (65)

Note that A_(DC) and B_(DC) are independent of current, while A_(AC) andB_(AC) depend on the current. Choosing as a form crossing over betweenEQNS. 64 and 65 results in the following expression for R_(AC):R _(AC)=½{1+tan h{α(T ₀ −T)}}{A _(AC) +B _(AC) T}+½{1−tan h{α(T ₀−T)}}{A _(DC) +B _(DC) T}T≦T ₀; and  (66)R _(AC)=½{1+tan h{β(T ₀ −T)}}{A _(AC) +B _(AC) T}+½{1−tan h{β(T ₀−T)}}{A _(DC) +B _(DC) T}T≧T ₀.

Since A_(AC) and B_(AC) are functions of current, then:A _(AC) =A _(AC) ⁽⁰⁾ +A _(AC) ⁽¹⁾ I; B _(AC) =B _(AC) ⁽⁰⁾ +B _(AC) ⁽¹⁾I.  (67)

The parameter α is also a function of current, and exhibits thequadratic dependence:α=α₀+α₁ I+α ₂ I ².  (68)

The parameters β, T₀, as well as A_(DC) and B_(DC) are independent ofcurrent. Values of the parameters for the copper/carbon steel/347Hheaters in the above experiments are listed in TABLE 2.

TABLE 2 Parameter Unit copper/carbon steel/347 H A_(DC) mΩ 0.6783 B_(DC)mΩ/° F.  6.53 × 10⁻⁴ A_(AC) ⁽⁰⁾ mΩ 3.6358 A_(AC) ⁽¹⁾ mΩ/A −1.247 × 10⁻³B_(AC) ⁽⁰⁾ mΩ/° F. 2.3575 × 10⁻³ B_(AC) ⁽¹⁾ mΩ/(° F. A)  −2.28 × 10⁻⁷ α₀1/° F. 0.2 α₁ 1/(° F. A)  −7.9 × 10⁻⁴ α₂ 1/(° F. A²)    8 × 10⁻⁷ β 1/°F. 0.017 T₀ ° F. 1350

FIGS. 190 A-C compare the results of the theoretical calculations inEQNS. 66-68 with the experimental data at 300 A (FIG. 190A), 400 A (FIG.190B) and 500 A (FIG. 190C). FIG. 190A depicts electrical resistance(mΩ) versus temperature (° F.) at 300 A. Data 1182 is the experimentaldata at 300 A. Curve 1184 is the theoretical calculation at 300 A. Curve1186 is a plot of resistance versus temperature at 10 A DC. FIG. 190Bdepicts electrical resistance (mΩ) versus temperature (° F.) at 400 A.Data 1188 is the experimental data at 400 A. Curve 1190 is thetheoretical calculation at 400 A. Curve 1192 is a plot of resistanceversus temperature at 10 A DC. FIG. 190C depicts electrical resistance(mΩ) versus temperature (° F.) at 500 A. Data 1194 is the experimentaldata at 500 A. Curve 1196 is the theoretical calculation at 500 A. Curve1198 is a plot of resistance versus temperature at 10 A DC. Note that,to obtain the resistance per foot, for example, in simulation work, theresistances given by the theoretical calculations must be divided bysix.

A numerical simulation (FLUENT available from Fluent USA, Lebanon, N.H.,U.S.A.) was used to compare operation of temperature limited heaterswith three turndown ratios. The simulation was done for heaters in anoil shale formation (Green River oil shale). Simulation conditions were:

-   -   61 m length conductor-in-conduit Curie heaters (center conductor        (2.54 cm diameter), conduit outer diameter 7.3 cm)    -   downhole heater test field richness profile for an oil shale        formation    -   16.5 cm (6.5 inch) diameter wellbores at 9.14 m spacing between        wellbores on triangular spacing    -   200 hours power ramp-up time to 820 watts/m initial heat        injection rate    -   constant current operation after ramp up    -   Curie temperature of 720.6° C. for heater    -   formation will swell and touch the heater canisters for oil        shale richnesses at least 0.14 L/kg (35 gals/ton)

FIG. 191 displays temperature (° C.) of a center conductor of aconductor-in-conduit heater as a function of formation depth (m) for atemperature limited heater with a turndown ratio of 2:1. Curves1200-1222 depict temperature profiles in the formation at various timesranging from 8 days after the start of heating to 675 days after thestart of heating (1200: 8 days, 1202: 50 days, 1204: 91 days, 1206: 133days, 1208: 216 days, 1210: 300 days, 1212: 383 days, 1214: 466 days,1216: 550 days, 1218: 591 days, 1220: 633 days, 1222: 675 days). At aturndown ratio of 2:1, the Curie temperature of 720.6° C. was exceededafter 466 days in the richest oil shale layers. FIG. 192 shows thecorresponding heater heat flux (W/m) through the formation for aturndown ratio of 2:1 along with the oil shale richness (1/kg) profile(curve 1224). Curves 1226-1258 show the heat flux profiles at varioustimes from 8 days after the start of heating to 633 days after the startof heating (1226: 8 days; 1228: 50 days; 1230: 91 days; 1232: 133 days;1234: 175 days; 1236: 216 days; 1238: 258 days; 1240: 300 days; 1232:341 days; 1244: 383 days; 1246: 425 days; 1248: 466 days; 1250: 508days; 1252: 550 days; 1254: 591 days; 1256: 633 days; 1258: 675 days).At a turndown ratio of 2:1, the center conductor temperature exceededthe Curie temperature in the richest oil shale layers.

FIG. 193 displays heater temperature (° C.) as a function of formationdepth (m) for a turndown ratio of 3:1. Curves 1260-1282 show temperatureprofiles through the formation at various times ranging from 12 daysafter the start of heating to 703 days after the start of heating (1260:12 days; 1262: 33 days; 1264: 62 days; 1266: 102 days; 1268: 146 days;1270: 205 days; 1272: 271 days; 1274: 354 days; 1276: 467 days; 1278:605 days; 1280: 662 days; 1282: 703 days). At a turndown ratio of 3:1,the Curie temperature was approached after 703 days. FIG. 194 shows thecorresponding heater heat flux (W/m) through the formation for aturndown ratio of 3:1 along with the oil shale richness (1/kg) profile(curve 1284). Curves 1286-1306 show the heat flux profiles at varioustimes from 12 days after the start of heating to 605 days after thestart of heating (1286: 12 days, 1288: 32 days, 1290: 62 days, 1292: 102days, 1294: 146 days, 1296: 205 days, 1298: 271 days, 1300: 354 days,1302: 467 days, 1304: 605 days, 1306: 749 days). The center conductortemperature never exceeded the Curie temperature for the turndown ratioof 3:1. The center conductor temperature also showed a relatively flattemperature profile for the 3:1 turndown ratio.

FIG. 195 shows heater temperature (° C.) as a function of formationdepth (m) for a turndown ratio of 4:1. Curves 1308-1328 show temperatureprofiles through the formation at various times ranging from 12 daysafter the start of heating to 467 days after the start of heating (1308:12 days; 1310: 33 days; 1312: 62 days; 1314: 102 days, 1316: 147 days;1318: 205 days; 1320: 272 days; 1322: 354 days; 1324: 467 days; 1326:606 days, 1328: 678 days). At a turndown ratio of 4:1, the Curietemperature was not exceeded even after 678 days. The center conductortemperature never exceeded the Curie temperature for the turndown ratioof 4:1. The center conductor showed a temperature profile for the 4:1turndown ratio that was somewhat flatter than the temperature profilefor the 3:1 turndown ratio. These simulations show that the heatertemperature stays at or below the Curie temperature for a longer time athigher turndown ratios. For this oil shale richness profile, a turndownratio of at least 3:1 may be desirable.

Simulations have been performed to compare the use of temperaturelimited heaters and non-temperature limited heaters in an oil shaleformation. Simulation data was produced for conductor-in-conduit heatersplaced in 16.5 cm (6.5 inch) diameter wellbores with 12.2 m (40 feet)spacing between heaters using a formation simulator (for example, STARS)and a near wellbore simulator (for example, ABAQUS from ABAQUS, Inc.,Providence, R.I., U.S.A.). Standard conductor-in-conduit heatersincluded 304 stainless steel conductors and conduits. Temperaturelimited conductor-in-conduit heaters included a metal with a Curietemperature of 760° C. for conductors and conduits. Results from thesimulations are depicted in FIGS. 196-198.

FIG. 196 depicts heater temperature (° C.) at the conductor of aconductor-in-conduit heater versus depth (m) of the heater in theformation for a simulation after 20,000 hours of operation. Heater powerwas set at 820 watts/meter until 760° C. was reached, and the power wasreduced to inhibit overheating. Curve 1330 depicts the conductortemperature for standard conductor-in-conduit heaters. Curve 1330 showsthat a large variance in conductor temperature and a significant numberof hot spots developed along the length of the conductor. Thetemperature of the conductor had a minimum value of 490° C. Curve 1332depicts conductor temperature for temperature limitedconductor-in-conduit heaters. As shown in FIG. 196, temperaturedistribution along the length of the conductor was more controlled forthe temperature limited heaters. In addition, the operating temperatureof the conductor was 730° C. for the temperature limited heaters. Thus,more heat input would be provided to the formation for a similar heaterpower using temperature limited heaters.

FIG. 197 depicts heater heat flux (W/m) versus time (yrs) for theheaters used in the simulation for heating oil shale. Curve 1334 depictsheat flux for standard conductor-in-conduit heaters. Curve 1336 depictsheat flux for temperature limited conductor-in-conduit heaters. As shownin FIG. 197, heat flux for the temperature limited heaters wasmaintained at a higher value for a longer period of time than heat fluxfor standard heaters. The higher heat flux may provide more uniform andfaster heating of the formation.

FIG. 198 depicts cumulative heat input (kJ/m)(kilojoules per meter)versus time (yrs) for the heaters used in the simulation for heating oilshale. Curve 1338 depicts cumulative heat input for standardconductor-in-conduit heaters. Curve 1340 depicts cumulative heat inputfor temperature limited conductor-in-conduit heaters. As shown in FIG.198, cumulative heat input for the temperature limited heaters increasedfaster than cumulative heat input for standard heaters. The fasteraccumulation of heat in the formation using temperature limited heatersmay decrease the time needed for retorting the formation. Onset ofretorting of the oil shale formation may begin around an averagecumulative heat input of 1.1×10⁸ kJ/meter. This value of cumulative heatinput is reached around 5 years for temperature limited heaters andbetween 9 and 10 years for standard heaters.

FIG. 199 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for iron alloy TC3 (0.1%by weight carbon, 5% by weight cobalt, 12% by weight chromium, 0.5% byweight manganese, 0.5% by weight silicon). Curve 1344 depicts weightpercentage of the ferrite phase. Curve 1346 depicts weight percentage ofthe austenite phase. The arrow points to the Curie temperature of thealloy. As shown in FIG. 199, the phase transformation is close to theCurie temperature but does not overlap with the Curie temperature forthis alloy.

FIG. 200 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for iron alloy FM-4(0.1% by weight carbon, 5% by weight cobalt, 0.5% by weight manganese,0.5% by weight silicon). Curve 1348 depicts weight percentage of theferrite phase. Curve 1350 depicts weight percentage of the austenitephase. The arrow points to the Curie temperature of the alloy. As shownin FIG. 200, the phase transformation broadens without chromium in thealloy and the phase transformation overlaps with the Curie temperaturefor this alloy.

FIG. 201 depicts the Curie temperature (solid horizontal bars) and phasetransformation temperature range (slashed vertical bars) for severaliron alloys. Column 1352 is for FM-2 iron-cobalt alloy. Column 1354 isfor FM-4 iron-cobalt alloy. Column 1356 is for FM-6 iron-cobalt alloy.Column 1358 is for FM-8 iron-cobalt alloy. Column 1360 is for TC1 410stainless steel alloy with cobalt. Column 1362 is for TC2 410 stainlesssteel alloy with cobalt. Column 1364 is for TC3 410 stainless steelalloy with cobalt. Column 1366 is for TC4 410 stainless steel alloy withcobalt. Column 1368 is for TC5 410 stainless steel alloy with cobalt. Asshown in FIG. 201, the iron-cobalt alloys (FM-2, FM-4, FM-6, FM-8) havelarge phase transformation temperature ranges that overlap with theCurie temperature. The 410 stainless steel alloys with cobalt (TC1, TC2,TC3, TC4, TC5) have small phase transformation temperature ranges. Thephase transformation temperature ranges for TC1, TC2, and TC3 are abovethe Curie temperature. The phase transformation temperature range forTC4 is below the Curie temperature. Thus, a temperature limited heaterusing TC4 may self-limit at a temperature below the Curie temperature ofthe TC4.

FIGS. 202-205 depict the effect of alloy addition to iron-cobalt alloys.FIGS. 202 and 203 depict the effect of carbon addition to an iron-cobaltalloy. FIGS. 204 and 205 depict the effect of titanium addition to aniron-cobalt alloy.

FIG. 202 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt and 0.4% by weight manganese. Curve 1370depicts weight percentage of the ferrite phase. Curve 1372 depictsweight percentage of the austenite phase. The arrow points to the Curietemperature of the alloy. As shown in FIG. 202, the phase transformationis close to the Curie temperature but does not overlap with the Curietemperature for this alloy.

FIG. 203 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt, 0.4% by weight manganese, and 0.01% carbon.Curve 1374 depicts weight percentage of the ferrite phase. Curve 1376depicts weight percentage of the austenite phase. The arrow points tothe Curie temperature of the alloy. As shown in FIGS. 202 and 203, thephase transformation broadens with the addition of carbon to the alloywith the onset of the phase transformation shifting to a lowertemperature. Thus, carbon can be added to an iron alloy to lower theonset temperature and broaden the temperature range of the phasetransformation.

FIG. 204 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt, 0.4% by weight manganese, and 0.085%carbon. Curve 1378 depicts weight percentage of the ferrite phase. Curve1380 depicts weight percentage of the austenite phase. The arrow pointsto the Curie temperature of the alloy. As shown in FIG. 204, the phasetransformation overlaps with the Curie temperature.

FIG. 205 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt, 0.4% by weight manganese, 0.085% carbon,and 0.4% titanium. Curve 1382 depicts weight percentage of the ferritephase. Curve 1384 depicts weight percentage of the austenite phase. Thearrow points to the Curie temperature of the alloy. As shown in FIGS.204 and 205, the phase transformation narrows with the addition oftitanium to the alloy with the onset of the phase transformationshifting to a higher temperature. Thus, titanium can be added to an ironalloy to raise the onset temperature and narrow the temperature range ofthe phase transformation.

Calculations may be made to determine the effect of a thermallyconductive fluid in an annulus of a temperature limited heater. Theequations below (EQNS. 69-79) are used to relate a heater center rodtemperature in a heated section to a conduit temperature adjacent to theheater center rod. In this example, the heater center rod is a 347Hstainless steel tube with outer radius b. The conduit is made of 347Hstainless steel and has inner radius R. The center heater rod and theconduit are at uniform temperatures T_(H) and T_(C), respectively. T_(C)is maintained constant and a constant heat rate, Q, per unit length issupplied to the center heater rod. T_(H) is the value at which the rateof heat per unit length transferred to the conduit by conduction andradiation balances the rate of heat generated, Q. Conduction across agap between the center heater rod and inner surface of the conduit isassumed to take place in parallel with radiation across the gap. Forsimplicity, radiation across the gap is assumed to be radiation across avacuum. The equations are thus:Q=Q _(C) +Q _(R);  (69)where Q_(C) represents the conductive component and Q_(R) represents theradiative component of the heat flux across the gap. Denoting the innerradius of the conduit by R, conductive heat transport satisfies theequation:

$\begin{matrix}{{Q_{C} = {{- 2}\;\pi\;{rk}_{g}\frac{\mathbb{d}T}{\mathbb{d}r}}};{b \leq r \leq R};} & (70)\end{matrix}$subject to the boundary conditions:T(b)=T _(H) ; T(R)=T _(C).  (71)The thermal conductivity of the gas in the gap, kg, is well described bythe equation:k _(g) =a _(g) +b _(g) T  (72)Substituting EQN. 72 into EQN. 70 and integrating subject to theboundary conditions in EQN. 71 gives:

$\begin{matrix}{{{{\frac{Q_{C}}{2\;\pi}{\ln\left( {R/b} \right)}} = {k_{g}^{({eff})}\left( {T_{H} - T_{C}} \right)}};}{with}} & (73) \\{k_{g}^{({eff})} = {a_{g} + {\frac{1}{2}{{b_{g}\left( {T_{H} + T_{C}} \right)}.}}}} & (74)\end{matrix}$The rate of radiative heat transport across the gap per unit length,Q_(R), is given by:Q _(R)=2πσb∈ _(R)∈_(bR) {T _(H) ⁴ −T _(C) ⁴};  (75)where∈_(bR)=∈_(b)/{∈_(R)+(b/R)∈_(b)(1−∈_(R))}.  (76)In EQNS. 75 and 76, ∈_(b) and ∈_(R) denote the emissivities of thecenter heater rod and inner surface of the conduit, respectively, and σis the Stefan-Boltzmann constant.

Substituting EQNS. 73 and 75 back into EQN. 69, and rearranging gives:

$\begin{matrix}{\frac{Q}{2\;\pi} = {\frac{k_{g}^{eff}\left( {T_{H} - T_{C}} \right)}{\ln\left( {R/b} \right)} + {\sigma\; b\; ɛ_{R}ɛ_{bR}{\left\{ {T_{H}^{4} - T_{C}^{4}} \right\}.}}}} & (77)\end{matrix}$To solve EQN. 77, t is denoted as the ratio of radiative to conductiveheat flux across the gap:

$\begin{matrix}{t = {\frac{\sigma\; b\; ɛ_{R}ɛ_{bR}\left\{ {T_{H}^{2} + T_{C}^{2}} \right\}\left( {T_{H} + T_{C}} \right){\ln\left( {R/b} \right)}}{k_{g}^{eff}}.}} & (78)\end{matrix}$Then EQN. 77 can be written in the form:

$\begin{matrix}{\frac{Q}{2\;\pi} = {\frac{k_{g}^{eff}\left( {T_{H} - T_{C}} \right)}{\ln\left( {R/b} \right)}{\left\{ {1 + t} \right\}.}}} & (79)\end{matrix}$EQNS. 79 and 77 are solved iteratively for T_(H) given Q and T_(C). Thenumerical values of the parameters σ, a_(g), and b_(g) are listed inTABLE 3. Heater dimensions are given in TABLE 4. The emissivities ∈_(S)and ∈_(a) may be taken to be in the range 0.4-0.8.

TABLE 3 Material Parameters Used in the Calculations Pa- ram- eter σa_(g) (air) b_(g) (air) a_(g) (He) b_(g) (He) Unit Wm⁻²K⁻⁴ Wm⁻¹K⁻¹Wm⁻¹K⁻² Wm⁻¹K⁻¹ Wm⁻¹K⁻² Value 5.67 × 10⁻⁸ 0.01274 5.493 × 10⁻⁵ 0.075222.741 × 10⁻⁴

TABLE 4 Set of Heater Dimensions Dimension Inches Meters Heater rodouter radius b ½ × 0.75 9.525 × 10⁻³ Conduit inner radius R ½ × 1.7712.249 × 10⁻²

FIG. 206 shows heater rod temperature (° C.) as a function of the power(W/m) generated within the heater rod for a base case in which both theheater rod and conduit emissivities were 0.8, and a low emissivity casein which the heater rod emissivity was lowered to 0.4. The conduittemperature was set at 260° C. Cases in which the annular space isfilled with air and with helium are compared in FIG. 206. Plot 1342 isfor the base case in air. Plot 1386 is for the base case in helium. Plot1388 is for the low emissivity case in air. Plot 1410 is for the lowemissivity case in helium. FIGS. 207-213 repeat the same cases forconduit temperatures of 315° C. to 649° C. inclusive, with incrementalsteps of 55° C. in each figure. Note that the temperature scale in FIGS.211-213 is offset by 111° C. with respect to the scale in FIGS. 206-210.FIGS. 206-213 show that helium in the annular space, which has a higherthermal conductivity than air, reduces the rod temperature for similarpower generation.

FIG. 214 shows a plot of center heater rod (with 0.8 emissivity)temperature (vertical axis) versus conduit temperature (horizontal axis)for various heater powers with air or helium in the annulus. FIG. 215shows a plot of center heater rod (with 0.4 emissivity) temperature(vertical axis) versus conduit temperature (horizontal axis) for variousheater powers with air or helium in the annulus. Plots 1412 are for airand a heater power of 500 W/m. Plots 1414 are for air and a heater powerof 833 W/m. Plots 1416 are for air and a heater power of 1167 W/m. Plots1418 are for helium and a heater power of 500 W/m. Plots 1420 are forhelium and a heater power of 833 W/m. Plots 1422 are for helium and aheater power of 1167 W/m. FIGS. 214 and 215 show that helium in theannular space, as compared to air in the annulus, reduces temperaturedifference between the heater and the canister.

FIG. 216 depicts spark gap breakdown voltages (V) versus pressure (atm)at different temperatures for a conductor-in-conduit heater with air inthe annulus. FIG. 217 depicts spark gap breakdown voltages (V) versuspressure (atm) at different temperatures for a conductor-in-conduitheater with helium in the annulus. FIGS. 216 and 217 show breakdownvoltages for a conductor-in-conduit heater with a 2.5 cm diameter centerconductor and a 7.6 cm gap to the inner radius of the conduit. Plot 1424is for a temperature of 300 K. Plot 1426 is for a temperature of 700 K.Plot 1428 is for a temperature of 1050 K. 480 V RMS is shown as atypical applied voltage. FIGS. 216 and 217 show that helium has a sparkgap breakdown voltage smaller than the spark gap breakdown voltage forair at 1 atm. Thus, the pressure of helium may need to be increased toachieve spark gap breakdown voltages on the order of breakdown voltagesfor air.

FIG. 218 depicts leakage current (mA) versus voltage (V) for alumina andsilicon nitride centralizers at selected temperatures. Leakage currentwas measured between a conductor and a conduit of a 0.91 mconductor-in-conduit section with two centralizers. Theconductor-in-conduit was placed horizontally in a furnace. Plot 1430depicts data for alumina centralizers at a temperature of 760° C. Plot1432 depicts data for alumina centralizers at a temperature of 815° C.Plot 1434 depicts data for gas pressure sintered reaction bonded siliconnitride centralizers at a temperature of 760° C. Plot 1436 depicts datafor gas pressure sintered reaction bonded silicon nitride at atemperature of 871° C. FIG. 218 shows that the leakage current ofalumina increases substantially from 760° C. to 815° C. while theleakage current of gas pressure sintered reaction bonded silicon nitrideremains relatively low from 760° C. to 871° C.

FIG. 219 depicts leakage current (mA) versus temperature (° F.) for twodifferent types of silicon nitride. Plot 1438 depicts leakage currentversus temperature for highly polished, gas pressure sintered reactionbonded silicon nitride. Plot 1440 depicts leakage current versustemperature for doped densified silicon nitride. FIG. 219 shows theimproved leakage current versus temperature characteristics of gaspressure sintered reaction bonded silicon nitride versus doped siliconnitride.

Using silicon nitride centralizers allows for smaller diameter andhigher temperature heaters. A smaller gap is needed between a conductorand a conduit because of the excellent electrical characteristics of thesilicon nitride. Silicon nitride centralizers may allow higher operatingvoltages (for example, up to at least 1500 V, 2000 V, 2500 V, or 15 kV)to be used in heaters due to the electrical characteristics of thesilicon nitride. Operating at higher voltages allows longer lengthheaters to be utilized (for example, lengths up to at least 500 m, 1000m, or 1500 m at 2500 V). In some embodiments, boron nitride is used as amaterial for centralizers or other electrical insulators. Boron nitrideis a better thermal conductor and has better electrical properties thansilicon nitride. Boron nitride does not absorb water readily (boronnitride is substantially non-hygroscopic). Boron nitride is available inat least a hexagonal form and a face centered cubic form. A hexagonalcrystalline formation of boron nitride has several desired properties,including, but not limited to, a high thermal conductivity and a lowfriction coefficient.

FIG. 220 depicts projected corrosion rates (metal loss per year) over aone-year period for several metals in a sulfidation atmosphere. Themetals were exposed to a gaseous mixture containing about 1% by volumeCOS, about 32% by volume CO and about 67% volume CO₂ at about 538° C.(1000° F.), at about 649° C. (1200° C.), at about 760° C. (1400° F.),and at about 871° C. (about 1600° F.) for 384 hours. The resulting datawas extrapolated to a one-year time period. The experimental conditionssimulates in-situ sub-surface formation sulfidation conditions of 10% H₂by volume, 10% H₂S by volume and 25% H₂O by volume at 870° C. Curve 1442depicts 625 stainless steel. Curve 1444 depicts CF8C+ stainless steel.Curve 1446 depicts data for 410 stainless steel. Curve 1448 depicts 2025 Nb stainless steel. Curve 1450 depicts 253 MA stainless steel. Curve1452 depicts 347H stainless steel. Curve 1454 depicts 446 stainlesssteel. 410 stainless steel exhibits a decrease in corrosion attemperatures between 500° C. and 650° C.

In some embodiments, cobalt may be added to 410 stainless steel todecrease the rate of corrosion at elevated temperatures (for example,temperatures greater than 1200° F.) relative to untreated 410 stainlesssteel. Addition of cobalt to 410 stainless steel may enhance thestrength of the stainless steel at high temperatures (for example,temperatures greater than 1200° F., greater than 1400° F., greater than1500° F., or greater than 1600° F.) and/or change the magneticcharacteristics of the metal. FIG. 221 depicts projected corrosion rates(metal loss per year) for 410 stainless steel and 410 stainless steelcontaining various amounts of cobalt in a sulfidation atmosphere. Themetals were exposed to the same conditions as the metals in FIG. 221.Bar 1456 depicts data for 410 stainless steel. Bar 1458 depicts data for410 stainless steel with 2.5% cobalt by weight. Bar 1460 depicts datafor 410 stainless steel with 5% cobalt by weight. Bar 1462 depicts datafor 410 stainless steel with 10% cobalt by weight. As the amount ofcobalt in the 410 stainless steel increases, the corrosion rate in asulfidation atmosphere decreases relative to non-cobalt containing 410stainless steel in a temperature range of about 800° C. to about 880° C.

A STARS simulation (Computer Modelling Group, LTD., Calgary, Alberta,Canada) determined heating properties using temperature limited heaterswith varying power outputs. FIG. 222 depicts an example of richness ofan oil shale formation (gal/ton) versus depth (ft). Upper portions ofthe formation (above about 1210 feet) tend to have a leaner richness,lower water-filled porosity, and/or less dawsonite than deeper portionsof the formation. For the simulation, a heater similar to the heaterdepicted in FIG. 90 was used. Portion 728 had a length of 368 feet abovethe dashed line shown in FIG. 222 and portion 726 had a length of 587feet below the dashed line.

In the first example, the temperature limited heater had constantthermal properties along the entire length of the heater. The heaterincluded a 0.565″ diameter copper core with a carbon steel conductor(Curie temperature of 1418° F., pure iron with outside diameter of0.825″) surrounding the copper core. The outer conductor was 347Hstainless steel surrounding the carbon steel conductor with an outsidediameter of 1.2″. The resistance per foot (mΩ/ft) versus temperature (°F.) profile of the heater is shown in FIG. 223. FIG. 224 depicts averagetemperature in the formation (° F.) versus time (days) as determined bythe simulation for the first example. Curve 1470 depicts averagetemperature versus time for the top portion of the formation. Curve 1472depicts average temperature versus time for the entire formation. Curve1474 depicts average temperature versus time for the bottom portion ofthe formation. As shown, the average temperature in the bottom portionof the formation lagged behind the average temperature in the topportion of the formation and the entire formation. The top portion ofthe formation reached an average temperature of 644° F. in 1584 days.The bottom portion of the formation reached an average temperature of644° F. in 1922 days. Thus, the bottom portion lagged behind the topportion by almost a year to reach an average temperature near apyrolysis temperature.

In the second example, portion 728 of the temperature limited heater hadthe same properties used in the first example. Portion 726 of the heaterwas altered to have a Curie temperature of 1550° F. by the addition ofcobalt to the iron conductor. FIG. 225 depicts resistance per foot(mΩ/ft) versus temperature (° F.) for the second heater example. Curve1476 depicts the resistance profile for the top portion (portion 728).Curve 1478 depicts the resistance profile for the bottom portion(portion 726). FIG. 226 depicts average temperature in the formation (°F.) versus time (days) as determined by the simulation for the secondexample. Curve 1480 depicts average temperature versus time for the topportion of the formation. Curve 1482 depicts average temperature versustime for the entire formation. Curve 1484 depicts average temperatureversus time for the bottom portion of the formation. As shown, theaverage temperature in the bottom portion of the formation lagged behindthe average temperature in the top portion of the formation and theentire formation. The top portion of the formation reached an averagetemperature of 644° F. in 1574 days. The bottom portion of the formationreached an average temperature of 644° F. in 1701 days. Thus, the bottomportion still lagged behind the top portion to reach an averagetemperature near a pyrolysis temperature but the time lag was less thanthe time lag in the first example.

FIG. 227 depicts net heater energy input (Btu) versus time (days) forthe second example. Curve 1486 depicts net heater energy input for thebottom portion. Curve 1488 depicts net heater input for the top portion.The net heater energy input to reach a temperature of 644° F. for thebottom portion was 2.35×10¹⁰ Btu. The net heater energy input to reach atemperature of 644° F. for the top portion was 1.32×10¹⁰ Btu. Thus, ittook 12% more power to reach the desired temperature in the bottomportion.

FIG. 228 depicts power injection per foot (W/ft) versus time (days) forthe second example. Curve 1490 depicts power injection rate for thebottom portion. Curve 1492 depicts power injection rate for the topportion. The power injection rate for the bottom portion was about 6%more than the power injection rate for the top portion. Thus, eitherreducing the power output of the top portion and/or increasing the poweroutput of the bottom portion to a total of about 6% should provideapproximately similar heating rates in the top and bottom portions.

In the third example, dimensions of the top portion (portion 728) werealtered to provide less power output. Portion 728 was adjusted to have acopper core with an outside diameter of 0.545″, a carbon steel conductorwith an outside diameter of 0.700″ surrounding the copper core, and anouter conductor of 347H stainless steel with an outside diameter of 1.2″surrounding the carbon steel conductor. The bottom portion (portion 726)had the same properties as the heater in the second example. FIG. 229depicts resistance per foot (mΩ/ft) versus temperature (° F.) for thethird heater example. Curve 1494 depicts the resistance profile for thetop portion (portion 728). Curve 1496 depicts the resistance profile ofthe top portion in the second example. Curve 1498 depicts the resistanceprofile for the bottom portion (portion 726). FIG. 230 depicts averagetemperature in the formation (° F.) versus time (days) as determined bythe simulation for the third example. Curve 1502 depicts averagetemperature versus time for the top portion of the formation. Curve 1500depicts average temperature versus time for the bottom portion of theformation. As shown, the average temperature in the bottom portion ofthe formation was approximately the same as the average temperature inthe top portion of the formation, especially after a time of about 1000days. The top portion of the formation reached an average temperature of644° F. in 1642 days. The bottom portion of the formation reached anaverage temperature of 644° F. in 1649 days. Thus, the bottom portionreached an average temperature near a pyrolysis temperature only 5 dayslater than the top portion.

FIG. 231 depicts cumulative energy injection (Btu) versus time (days)for each of the three heater examples. Curve 1508 depicts cumulativeenergy injection for the first heater example. Curve 1506 depictscumulative energy injection for the second heater example. Curve 1504depicts cumulative energy injection for the third heater example. Thesecond and third heater examples have nearly identical cumulative energyinjections. The first heater example had a cumulative energy injectionabout 7% higher to reach an average temperature of 644° F. in the bottomportion.

FIGS. 222-231 depict results for heaters with a 40 foot spacing betweenheaters in a triangular heating pattern. FIG. 232 depicts averagetemperature (° F.) versus time (days) for the third heater example witha 30 foot spacing between heaters in the formation as determined by thesimulation. Curve 1510 depicts average temperature versus time for thetop portion of the formation. Curve 1512 depicts average temperatureversus time for the bottom portion of the formation. The curves in FIG.232 still tracked with approximately equal heating rates in the top andbottom portions. The time to reach an average temperature in theportions was reduced. The top portion of the formation reached anaverage temperature of 644° F. in 903 days. The bottom portion of theformation reached an average temperature of 644° F. in 884 days. Thus,the reduced heater spacing decreases the time needed to reach an averageselected temperature in the formation.

As a fourth example, the STARS simulation was used to determine heatingproperties of temperature limited heaters with varying power outputswhen using the temperature limited heaters in the heater configurationand pattern depicted in FIGS. 124 and 126. The heater pattern had a 30foot heater spacing. Portion 728 had a length of 368 feet and portion726 had a length of 587 feet as in the previous examples. Portion 728included a solid 410 stainless steel conductor with an outside diameterof 1.25″. Portion 726 included a solid 410 stainless steel conductorwith 9% by weight cobalt added. The Curie temperature of portion 726 is230° F. higher than the Curie temperature of portion 728.

FIG. 233 depicts average temperature (° F.) versus time (days) for thefourth heater example using the heater configuration and patterndepicted in FIGS. 124 and 126 as determined by the simulation. Curve1514 depicts average temperature versus time for the top portion of theformation. Curve 1516 depicts average temperature versus time for thebottom portion of the formation. The curves in FIG. 233 showapproximately equal heating rates in the top and bottom portions. Thetop portion of the formation reached a temperature of 644° F. in 859days. The bottom portion of the formation reached a temperature of 644°F. in 880 days. In this heater configuration and heater pattern, the topportion of the formation reached a selected temperature at about thesame time as a bottom portion of the formation.

In some in situ conversion embodiments, a downhole gas turbine is usedto provide a portion of the electricity for an electric heater. Theexhaust from the gas turbine may heat the formation. The heater may be atemperature limited heater in a horizontal section of a U-shaped well.In some embodiments, the substantially horizontal section of theU-shaped well is over 1000 m long, over 1300 m long, over 1600 m long,or over 1900 m long.

FIG. 234 depicts a schematic representation of a heating system with adownhole gas turbine. Gas turbine 1520 is placed at or near thetransition between overburden 382 and hydrocarbon layer 380. Gas turbine1520 may include electrical generator 1522 and turbine gas combustor1524. Inlet leg 1526 to gas turbine 1520 may have a relatively largediameter. The diameter may be 0.3 m, 0.4 m, 0.5 m or greater. Oxidantline 1528 and fuel line 1530 supply gas turbine 1520. In someembodiments, fuel line 1530 is placed within oxidant line 1528, or theoxidant line is placed in the fuel line. In some embodiments, theoxidant line is positioned adjacent to the fuel line. In someembodiments, inlet oxidant and fuel are used to cool gas turbine 1520.Oxidant may be, but is not limited to, air, oxygen, or oxygen enrichedair.

Electricity provided by electrical generator 1522 is directed totemperature limited heater 1532 through lead-in conductors 1534. Lead-inconductors 1534 may be insulated conductors. If electrical generator1522 is not able to supply enough electricity to temperature limitedheater 1532 to heat hydrocarbon layer 380 to a desired temperature,additional electricity may be supplied to the temperature limited heaterthrough a conductor placed in inlet leg 1522 and electrically coupled tothe temperature limited heater.

Exhaust gas from gas turbine 1524 passes through tubular 1536 to outlet1538. In an embodiment, the tubular is 4″ stainless steel pipe placed ina 6″ wellbore. The exhaust gases heat an initial section of hydrocarbonlayer 380 before the gases become too cool to heat the hydrocarbon layerto the desired temperature. Temperature limited heater 1532 begins aselected distance from gas turbine 1520. The distance may be 200 m, 150m, 100 m, or less. Heat provided to the portion of the formation fromgas turbine 1520 to temperature limited heater 1532 may come from theexhaust gases passing through tubular 1536. Temperature limited heater1532, which is at least partially supplied with electricity generated bygas turbine 1520, heats hydrocarbon layer 380 and the exhaust gases fromthe gas turbine. Temperature limited heater 1532 may be an insulatedconductor heater with a self-limiting temperature of about 760° C. Insome embodiments, temperature limited heater 1532 is placed in tubular1536. In other embodiments, the temperature limited heater is on theoutside of the tubular. Temperature limited heater 1532 may end at aselected horizontal distance from the outlet 1538 of the temperaturelimited heater. The distance may be 200 m, 150 m, 100 m, or less. Theexhaust gases heated by temperature limited heater 1532 transfer heat tohydrocarbon layer 380 before passing through overburden 382 to outlet1538.

Inlets and outlets of the U-shaped wells for heating a portion of theformation may be placed in alternating directions in adjacent wells.Alternating inlets and outlets of the U-shaped wells may allow foruniform heating of the hydrocarbon layer of the formation.

In some embodiments, a portion of oxidant for gas turbine 1520 is routedto the gas turbine from outlet 1538 of an adjacent U-shaped well. Theportion of oxidant may be sent to the gas turbine through a separateline. Using oxidant from the exit of the adjacent well may allow some ofthe oxidant and/or heat from the exiting exhaust gases to be recoveredand utilized. The separate exhaust gas line to the gas turbine maytransfer heat to the main oxidant line and/or fuel line to the gasturbine.

Compressors and partial expanders may be located at the surface.Compressed fuel lines and oxidant lines extend to gas turbine 1520.Generators, burners, and expanders of the gas turbine may be located ator near the transition between the overburden and the hydrocarbon layerthat is to be heated. Locating equipment in this manner may reduce thecomplexity of the downhole equipment, and reduce pressure drops for theoxidant going down the wellbore and the combustion gases going throughthe heater sections and back to the surface. The surface expander for afirst well can expand gases from an adjacent well outlet since theadjacent well outlet is physically closer to the inlet of the first wellthan is the outlet of the first well. Moving compressed fuel andcompressed oxidant down to the gas turbine may result in less pressuredrop as compared to having cool fuel and oxidant travel down to the gasturbine. Placing gas turbine 1520 at or near the transition betweenoverburden 382 and hydrocarbon layer 380 allows exhaust gas from the gasturbine to heat portions of the formation that are to be pyrolyzed.Placing the gas turbine 1520 at or near the transition betweenoverburden 382 and hydrocarbon layer 380 may eliminate or reduce theamount of insulation needed between the overburden and inlet leg 1526.In some embodiments, tapered insulation may be applied at the exit ofgas turbine 1520 to reduce excess heating of the formation near the gasturbine.

In some in situ conversion process embodiments, a circulation system isused to heat the formation. The circulation system may be a closed loopcirculation system. FIG. 235 depicts a schematic representation of asystem for heating a formation using a circulation system. The systemmay be used to heat hydrocarbons that are relatively deep in the groundand that are in formations that are relatively large in extent. In someembodiments, the hydrocarbons may be 100 m, 200 m, 300 m or more belowthe surface. The circulation system may also be used to heathydrocarbons that are not as deep in the ground. The hydrocarbons may bein formations that extend lengthwise up to 500 m, 750 m, 1000 m, ormore. The circulation system may become economically viable informations where the length of the hydrocarbon containing formation tobe treated is long compared to the thickness of the overburden. Theratio of the hydrocarbon formation extent to be heated by heaters to theoverburden thickness may be at least 3, at least 5, or at least 10. Theheaters of the circulation system may be positioned relative to adjacentheaters so that superposition of heat between heaters of the circulationsystem allows the temperature of the formation to be raised at leastabove the boiling point of aqueous formation fluid in the formation.

In some embodiments, heaters 534 may be formed in the formation bydrilling a first wellbore and then drilling a second wellbore thatconnects with the first wellbore. Piping may be positioned in theU-shaped wellbore to form U-shaped heater 534. Heaters 534 are connectedto heat transfer fluid circulation system 1540 by piping. Gas at highpressure may be used as the heat transfer fluid in the closed loopcirculation system. In some embodiments, the heat transfer fluid iscarbon dioxide. Carbon dioxide is chemically stable at the requiredtemperatures and pressures and has a relatively high molecular weightthat results in a high volumetric heat capacity. Other fluids such assteam, air, helium and/or nitrogen may also be used. The pressure of theheat transfer fluid entering the formation may be 3000 kPa or higher.The use of high pressure heat transfer fluid allows the heat transferfluid to have a greater density, and therefore a greater capacity totransfer heat. Also, the pressure drop across the heaters is less for asystem where the heat transfer fluid enters the heaters at a firstpressure for a given mass flow rate than when the heat transfer fluidenters the heaters at a second pressure at the same mass flow rate whenthe first pressure is greater than the second pressure.

Heat transfer fluid circulation system 1540 may include heat supply1542, first heat exchanger 1544, second heat exchanger 1546, andcompressor 1548. Heat supply 1542 heats the heat transfer fluid to ahigh temperature. Heat supply 1542 may be a furnace, solar collector,reactor, fuel cell exhaust heat, or other high temperature source ableto supply heat to the heat transfer fluid. In the embodiment depicted inFIG. 235, heat supply 1542 is a furnace that heats the heat transferfluid to a temperature in a range from about 700° C. to about 920° C.,from about 770° C. to about 870° C., or from about 800° C. to about 850°C. In an embodiment, heat supply 1542 heats the heat transfer fluid to atemperature of about 820° C. The heat transfer fluid flows from heatsupply 1542 to heaters 534. Heat transfers from heaters 534 to formation444 adjacent to the heaters. The temperature of the heat transfer fluidexiting formation 444 may be in a range from about 350° C. to about 580°C., from about 400° C. to about 530° C., or from about 450° C. to about500° C. In an embodiment, the temperature of the heat transfer fluidexiting formation 444 is about 480° C. The metallurgy of the piping usedto form heat transfer fluid circulation system 1540 may be varied tosignificantly reduce costs of the piping. High temperature steel may beused from heat supply 1542 to a point where the temperature issufficiently low so that less expensive steel can be used from thatpoint to first heat exchanger 1544. Several different steel grades maybe used to form the piping of heat transfer fluid circulation system1540.

Heat transfer fluid from heat supply 1542 of heat transfer fluidcirculation system 1540 passes through overburden 382 of formation 444to hydrocarbon layer 380. Portions of heaters 534 extending throughoverburden 382 may be insulated. In some embodiments, the insulation orpart of the insulation is a polyimide insulating material. Inletportions of heaters 534 in hydrocarbon layer 380 may have taperinginsulation to reduce overheating of the hydrocarbon layer near the inletof the heater into the hydrocarbon layer.

In some embodiments, the diameter of the pipe in overburden 382 may besmaller than the diameter of pipe through hydrocarbon layer 380. Thesmaller diameter pipe through overburden 382 may allow for less heattransfer to the overburden. Reducing the amount of heat transfer tooverburden 382 reduces the amount of cooling of the heat transfer fluidsupplied to pipe adjacent to hydrocarbon layer 380. The increased heattransfer in the smaller diameter pipe due to increased velocity of heattransfer fluid through the small diameter pipe is offset by the smallersurface area of the smaller diameter pipe and the decrease in residencetime of the heat transfer fluid in the smaller diameter pipe.

After exiting formation 444, the heat transfer fluid passes throughfirst heat exchanger 1544 and second heat exchanger 1546 to compressor1548. First heat exchanger 1544 transfers heat between heat transferfluid exiting formation 444 and heat transfer fluid exiting compressor1548 to raise the temperature of the heat transfer fluid that entersheat supply 1542 and reduce the temperature of the fluid exitingformation 444. Second heat exchanger 1546 further reduces thetemperature of the heat transfer fluid before the heat transfer fluidenters compressor 1548.

FIG. 236 depicts a plan view of an embodiment of wellbore openings inthe formation that is to be heated using the circulation system. Heattransfer fluid entries 1550 into formation 444 alternate with heattransfer fluid exits 1552. Alternating heat transfer fluid entries 1550with heat transfer fluid exits 1552 may allow for more uniform heatingof the hydrocarbons in formation 444.

The circulation system may be used to heat a portion of the formation.Production wells in the formation are used to remove produced fluids.After production from the formation has ended, the circulation systemmay be used to recover heat from the formation. Heat transfer fluid maybe circulated through heaters 534 after heat supply 1542 (depicted inFIG. 235) is disconnected from the circulation system. The heat transferfluid may be a different heat transfer fluid than the heat transferfluid used to heat the formation. Heat transfers from the heatedformation to the heat transfer fluid. The heat transfer fluid may beused to heat another portion of the formation or the heat transfer fluidmay be used for other purposes. In some embodiments, water is introducedinto heaters 534 to produce steam. In some embodiments, low temperaturesteam is introduced into heaters 534 so that the passage of the steamthrough the heaters increases the temperature of the steam. Other heattransfer fluids including natural or synthetic oils, such as Sylthermoil (Dow Corning Corporation (Midland, Mich., U.S.A.), may be usedinstead of steam or water.

In some embodiments, the circulation system may be used in conjunctionwith electrical heating. In some embodiments, at least a portion of thepipe in the U-shaped wellbores adjacent to portions of the formationthat are to be heated is made of a ferromagnetic material. For example,the piping adjacent to a layer or layers of the formation to be heatedis made of a 9% to 13% chromium steel, such as 410 stainless steel. Thepipe may be a temperature limited heater when time varying electriccurrent is applied to the piping. The time varying electric current mayresistively heat the piping, which heats the formation. In someembodiments, direct electric current may be used to resistively heat thepiping, which heats the formation.

In some embodiments, the circulation system is used to heat theformation to a first temperature, and electrical energy is used tomaintain the temperature of the formation and/or heat the formation tohigher temperatures. The first temperature may be sufficient to vaporizeaqueous formation fluid in the formation. The first temperature may beat most about 200° C., at most about 300° C., at most about 350° C., orat most about 400° C. Using the circulation system to heat the formationto the first temperature allows the formation to be dry when electricityis used to heat the formation. Heating the dry formation may minimizeelectrical current leakage into the formation.

In some embodiments, the circulation system and electrical heating maybe used to heat the formation to a first temperature. The formation maybe maintained, or the temperature of the formation may be increased fromthe first temperature, using the circulation system and/or electricalheating. In some embodiments, the formation may be raised to the firsttemperature using electrical heating, and the temperature may bemaintained and/or increased using the circulation system. Economicfactors, available electricity, availability of fuel for heating theheat transfer fluid, and other factors may be used to determine whenelectrical heating and/or circulation system heating are to be used.

In certain embodiments, the portion of heater 534 in hydrocarbon layer380 is coupled to lead-in conductors. Lead-in conductors may be locatedin overburden 382. Lead-in conductors may electrically couple theportion of heater 534 in hydrocarbon layer 380 to one or more wellheadsat the surface. Electrical isolators may be located at a junction of theportion of heater 534 in hydrocarbon layer 380 with portions of heater534 in overburden 382 so that the portions of the heater in theoverburden are electrically isolated from the portion of the heater inthe hydrocarbon layer. In some embodiments, the lead-in conductors areplaced inside of the pipe of the closed loop circulation system. In someembodiments, the lead-in conductors are positioned outside of the pipeof the closed loop circulation system. In some embodiments, the lead-inconductors are insulated conductors with mineral insulation, such asmagnesium oxide. The lead-in conductors may include highly electricallyconductive materials such as copper or aluminum to reduce heat losses inoverburden 382 during electrical heating.

In certain embodiments, the portions of heater 534 in overburden 382 maybe used as lead-in conductors. The portions of heater 534 in overburden382 may be electrically coupled to the portion of heater 534 inhydrocarbon layer 380. In some embodiments, one or more electricallyconducting materials (such as copper or aluminum) are coupled (forexample, cladded or welded) to the portions of heater 534 in overburden382 to reduce the electrical resistance of the portions of the heater inthe overburden. Reducing the electrical resistance of the portions ofheater 534 in overburden 382 reduces heat losses in the overburdenduring electrical heating.

In some embodiments, the portion of heater 534 in hydrocarbon layer 380is a temperature limited heater with a self-limiting temperature betweenabout 600° C. and about 1000° C. The portion of heater 534 inhydrocarbon layer 380 may be a 9% to 13% chromium stainless steel. Forexample, portion of heater 534 in hydrocarbon layer 380 may be 410stainless steel. Time-varying current may be applied to the portion ofheater 534 in hydrocarbon layer 380 so that the heater operates as atemperature limited heater.

FIG. 237 depicts a side view representation of an embodiment of a systemfor heating a portion of a formation using a circulated fluid systemand/or electrical heating. Wellheads 418 of heaters 534 may be coupledto heat transfer fluid circulation system 1540 by piping. Wellheads 418may also be coupled to electrical power supply system 1554. In someembodiments, heat transfer fluid circulation system 1540 is disconnectedfrom the heaters when electrical power is used to heat the formation. Insome embodiments, electrical power supply system 1554 is disconnectedfrom the heaters when heat transfer fluid circulation system 1540 isused to heat the formation.

Electrical power supply system 1554 may include transformer 900 andcables 894, 896. In certain embodiments, cables 894, 896 are capable ofcarrying high currents with low losses. For example, cables 894, 896 maybe thick copper or aluminum conductors. The cables may also have thickinsulation layers. In some embodiments, cable 894 and/or cable 896 maybe superconducting cables. The superconducting cables may be cooled byliquid nitrogen. Superconducting cables are available from Superpower,Inc. (Schenectady, N.Y., U.S.A.). Superconducting cables may minimizepower loss and/or reduce the size of the cables needed to coupletransformer 900 to the heaters.

Alternative energy sources may be used to supply electricity forsubsurface electric heaters. Alternative energy sources include, but arenot limited to, wind, off-peak power, hydroelectric power, geothermal,solar, and tidal wave action. Some of these alternative energy sourcesprovide intermittent, time-variable power, or power-variable power. Toprovide power for subsurface electric heaters, power provided by thesealternative energy sources may be conditioned to produce power withappropriate operating parameters (for example, voltage, frequency,and/or current) for the subsurface heaters.

FIG. 238 illustrates a schematic of an embodiment using wind to generateelectricity for subsurface heaters. The generated electrical power maybe used to power other equipment used to treat a subsurface formationsuch as, but not limited to, pumps, computers, or other electricalequipment. In certain embodiments, windmill 1560 is used to generateelectricity to power heaters 534. Windmill 1560 may represent one ormore windmills in a wind farm. The windmills convert wind to a usablemechanical form of motion. In some embodiments, the wind farm mayinclude advanced windmills as suggested by the National Renewable EnergyLaboratory (Golden, Colo., U.S.A.). In some embodiments, windmill 1560includes other intermittent, time-variable, or power-variable powersources.

In some embodiments, gas turbine 1562 is used to generate electricity topower heaters 534. Windmill 1560 and/or gas turbine 1562 may be coupledto transformer 1564. Transformer 1564 may convert power from windmill1560 and/or gas turbine 1562 into electrical power with appropriateoperating parameters for heaters 534 (for example, AC or DC power withappropriate voltage, current, and/or frequency may be generated by thetransformer).

In certain embodiments, tap controller 1566 is coupled to transformer1564, control system 1568 and heaters 534. Tap controller 1566 maymonitor and control transformer 1564 to maintain a constant voltage toheaters 534, regardless of the load of the heaters. Tap controller 1566may control power output in a range from 5 MVA (megavolt amps) to 500MVA, from 10 MVA to 400 MVA, or from 20 MVA to 300 MVA. As an example,during operation, an overload of voltage may be sent from transformer1564. Tap controller 1566 may distribute the excess load to otherheaters and/or other equipment in need of power. In some embodiments,tap controller 1566 may store the excess load for future use.

Control system 1568 may control tap controller 1566. Control system 1568may be, for example, a computer controller or an analog logic system.Control system 1568 may use data supplied from power sensors 1570 togenerate predictive algorithms and/or control tap controller 1566. Forexample, data may be an amount of power generated from windmill 1560,gas turbine 1562, and/or transformer 1564. Data may also include anamount of resistive load of heaters 534.

Automatic voltage regulation for resistive load of a heater maintainsthe life of the heaters and/or allows constant heat output from theheaters to a subsurface formation. Adjusting the load demands instead ofadjusting the power source allows enhanced control of power supplied toheaters and/or other equipment that requires electricity. Power suppliedto heaters 534 may be controlled within selected limits (for example, apower supplied and/or controlled to a heater within 1%, 5%, 10%, or 20%of power required by the heater). Control of power supplied fromalternative energy sources may allow output of prime power at itsrating, allow energy produced (for example, from an intermittent source,a subsurface formation, or a hydroelectric source) to be stored and usedlater, and/or allow use of power generated by intermittent power sourcesto be used as a constant source of energy.

Some hydrocarbon containing formations, such as oil shale formations,may include nahcolite, trona, dawsonite, and/or other minerals withinthe formation. In some embodiments, nahcolite is contained in unleachedportions of the formation. Unleached portions of the formation are partsof the formation where minerals are not removed by groundwater in theformation. For example, in the Piceance basin in Colorado, unleached oilshale is found below a depth of about 500 m below grade. Deep unleachedoil shale formations in the Piceance basin center tend to be relativelyrich in hydrocarbons. For example, about 0.10 liters to about 0.15liters of oil per kilogram (L/kg) of oil shale may be producible from anunleached oil shale formation.

Nahcolite is a mineral that includes sodium bicarbonate (NaHCO₃).Nahcolite may be found in formations in the Green River lakebeds inColorado, U.S.A. In some embodiments, at least about 5 weight %, atleast about 10 weight %, or at least about 20 weight % nahcolite may bepresent in the formation. Dawsonite is a mineral that includes sodiumaluminum carbonate (NaAl(CO₃)(OH)₂). Dawsonite is typically present inthe formation at weight percents greater than about 2 weight % or, insome embodiments, greater than about 5 weight %. Nahcolite and/ordawsonite may dissociate at temperatures used in the in situ conversionprocess. The dissociation is strongly endothermic and may produce largeamounts of carbon dioxide.

Nahcolite and/or dawsonite may be solution mined prior to, during,and/or following treatment of the formation in situ to avoiddissociation reactions and/or to obtain desired chemical compounds. Incertain embodiments, hot water or steam is used to dissolve nahcolite insitu to form an aqueous sodium bicarbonate solution before the in situconversion process is used to process hydrocarbons in the formation.Nahcolite may form sodium ions (Na⁺) and bicarbonate ions (HCO₃ ⁻) inaqueous solution. The solution may be produced from the formationthrough production wells, thus avoiding dissociation reactions duringthe in situ conversion process. In some embodiments, dawsonite isthermally decomposed to alumina during the in situ conversion processfor treating hydrocarbons in the formation. The alumina is solutionmined after completion of the in situ conversion process.

Formations that include nahcolite and/or dawsonite may be treated usingthe in situ conversion process. A perimeter barrier may be formed aroundthe portion of the formation to be treated. The perimeter barrier mayinhibit migration of water into the treatment area. During solutionmining and/or the in situ conversion process, the perimeter barrier mayinhibit migration of dissolved minerals and formation fluid from thetreatment area. During initial heating, a portion of the formation to betreated may be raised to a temperature below the dissociationtemperature of the nahcolite. The first temperature may be at most about90° C., or in some embodiments, at most about 80° C. The firsttemperature may be any temperature that increases the solvation rate ofnahcolite in water, but is also below a temperature at which nahcolitedissociates (above about 95° C. at atmospheric pressure).

A first fluid may be injected into the heated portion. The first fluidmay include water, brine, steam, or other fluids that form a solutionwith nahcolite and/or dawsonite. The first fluid may be at an increasedtemperature, for example, about 90° C., about 95° C., or about 100° C.The increased temperature may be similar to the first temperature of theportion of the formation.

In some embodiments, the first fluid is injected at an increasedtemperature into a portion of the formation that has not been heated byheat sources. The increased temperature may be a temperature below aboiling point of the first fluid, for example, about 90° C. for water.Providing the first fluid at an increased temperature increases atemperature of a portion of the formation. In certain embodiments,additional heat may be provided from one or more heat sources in theformation after the first fluid is injected.

In other embodiments, the first fluid is or includes steam. The steammay be produced by forming steam in a previously heated portion of theformation (for example by passing water through conduits that have beenused to heat the formation), by heat exchange with fluids produced fromthe formation, and/or by generating steam in standard steam productionfacilities.

In some embodiments, heat from a hot previously treated portion of theformation is used to heat water, brine, and/or steam used for solutionmining a new portion of the formation. Heat transfer fluid may beintroduced into the hot previously treated portion of the formation. Theheat transfer fluid may be water, steam, carbon dioxide, or otherfluids. Heat may transfer from the hot formation to the heat transferfluid. The heat transfer fluid is produced from the formation throughproduction wells. The heat transfer fluid is sent to a heat exchanger.The heat exchanger may heat water, brine, and/or steam used as the firstfluid to solution mine the new portion of the formation. The heattransfer fluid may be reintroduced into the heated portion of theformation to produce additional hot heat transfer fluid. In someembodiments, heat transfer fluid produced from the formation is treatedto remove hydrocarbons or other materials before being reintroduced intothe formation as part of a remediation process of the heated portion ofthe formation. Steam injected for solution mining may have a temperaturebelow the pyrolysis temperature of hydrocarbons in the formation.Injected steam may be at a temperature below 250° C., below 300° C., orbelow 400° C. The injected steam may be at a temperature of at least150° C., at least 135° C., or at least 125° C. Injecting steam atpyrolysis temperatures may cause problems as hydrocarbons pyrolyze andhydrocarbon fines mix with the steam. The mixture of fines and steam mayreduce permeability and/or cause plugging of production wells and theformation. Thus, the injected steam temperature is selected to inhibitplugging of the formation and/or wells in the formation. The temperatureof the injected steam may be varied during the solution mining process.As the solution mining progresses and the nahcolite being solution minedis farther away from the injection point, the steam temperature may beincreased so that steam and/or water that reaches the nahcolite to besolution mined is at an elevated temperature below the dissociationtemperature of the nahcolite.

A second fluid may be produced from the formation following injection ofthe first fluid into the formation. The second fluid may includeproducts of the injected first fluid in the formation. For example, thesecond fluid may include carbonic acid or other hydrated carbonatecompounds formed from the dissolution of nahcolite in the first fluid.The second fluid may also include minerals and/or metals. The mineralsand/or metals may include sodium, aluminum, phosphorus, and otherelements. Producing the second fluid from the formation may reduce theamount of energy required to heat the formation by removing mass and byremoving minerals that would otherwise undergo endothermic reactions.

Solution mining the formation before the in situ conversion processallows initial heating of the formation to be provided by heat transferfrom the first fluid used during solution mining. Solution miningnahcolite or other minerals that decompose or dissociate by means ofendothermic reactions before the in situ conversion process avoidshaving energy supplied to heat the formation being used to support theseendothermic reactions. Solution mining allows for production of mineralswith commercial value. Removing nahcolite or other minerals before thein situ conversion process removes mass from the formation. Thus, lessmass is present in the formation that needs to be heated to highertemperatures and heating the formation to higher temperatures may beachieved more quickly and/or more efficiently. Removing mass from theformation also may increase the permeability of the formation.Increasing the permeability may reduce the number of production wellsneeded for the in situ conversion process. In certain embodiments,solution mining before the in situ conversion process reduces the timedelay between startup of heating of the formation and production ofhydrocarbons by two years or more.

FIG. 239 depicts an embodiment for solution mining the formation.Barrier 454 (for example, a frozen barrier or a grout barrier) may beformed around a perimeter of treatment area 424 of the formation. Thefootprint defined by the barrier may have any desired shape such ascircular, square, rectangular, polygonal, or irregular shape. Barrier454 may be any barrier formed to inhibit the flow of fluid into or outof treatment area 424. For example, barrier 454 may include one or morefreeze wells that inhibit water flow through the barrier. Barrier 454may be formed using one or more barrier wells 200. Formation of barrier454 may be monitored using monitor wells 462 and/or by monitoringdevices placed in barrier wells 200.

Water inside treatment area 424 may be pumped out of the treatment areathrough injection wells 916 and/or production wells 206. In certainembodiments, injection wells 916 are used as production wells 206 andvice versa (the wells are used as both an injection well and aproduction well). Water may be pumped out until a production rate ofwater is low or stops.

Heat may be provided to treatment area 424 through heater wells 502. Insome embodiments, treatment area 424 is heated to a temperature fromabout 90° C. to about 120° C. (for example, a temperature of about 90°C., 95° C., 100° C., 110° C., or 120° C.). In certain embodiments, heatis provided to treatment area 424 from the first fluid injected into theformation. The first fluid may be injected at a temperature from about90° C. to about 120° C. (for example, a temperature of about 90° C., 95°C., 100° C., 110° C., or 120° C.). In some embodiments, heater wells 502are installed in treatment area 424 after the treatment area is solutionmined. In some embodiments, some heat is provided from heaters placed ininjection wells 916 and/or production wells 206. A temperature oftreatment area 424 may be monitored using temperature measurementdevices placed in monitoring wells 494 and/or temperature measurementdevices in injection wells 916, production wells 206, and/or heaterwells 502.

The first fluid is injected through one or more injection wells 916. Insome embodiments, the first fluid is hot water. The first fluid may mixand/or combine with non-hydrocarbon material that is soluble in thefirst fluid, such as nahcolite, to produce a second fluid. The secondfluid may be removed from the treatment area through injection wells916, production wells 206, and/or heater wells 502. Injection wells 916,production wells 206, and/or heater wells 502 may be heated duringremoval of the second fluid. Heating one or more wells during removal ofthe second fluid may maintain the temperature of the fluid duringremoval of the fluid from the treatment area above a desired value.After producing a majority of the soluble non-hydrocarbon material fromtreatment area 424, solution remaining within the treatment area may beremoved from the treatment area through injection wells 916, productionwells 206, and/or heater wells 502. Removing the soluble non-hydrocarbonmaterial may produce a relatively high permeability treatment area 424.

Hydrocarbons within treatment area 424 may be pyrolyzed and/or producedusing the in situ conversion process following removal of the solublenon-hydrocarbon materials. The relatively high permeability treatmentarea allows for easy movement of hydrocarbon fluids in the formationduring in situ conversion processing. The relatively high permeabilitytreatment area provides an enhanced collection area for pyrolyzed andmobilized fluids in the formation. During the in situ conversionprocess, heat may be provided to treatment area 424 through heater wells502. A mixture of hydrocarbons may be produced from the formationthrough production wells 206 and/or heater wells 502. In certainembodiments, injection wells 916 are used as either production wellsand/or heater wells during the in situ conversion process.

In some embodiments, a controlled amount of oxidant (for example, airand/or oxygen) is provided to treatment area 424 at or near heater wells502 when a temperature in the formation is above a temperaturesufficient to support oxidation of hydrocarbons. At such a temperature,the oxidant reacts with the hydrocarbons to provide heat in addition toheat provided by electrical heaters in heater wells 502. The controlledamount of oxidant may facilitate oxidation of hydrocarbons in theformation to provide additional heat for pyrolyzing hydrocarbons in theformation. The oxidant may more easily flow through treatment area 424because of the increased permeability of the treatment area afterremoval of the non-hydrocarbon materials. The oxidant may be provided ina controlled manner to control the heating of the formation. The amountof oxidant provided is controlled so that uncontrolled heating of theformation is avoided.

Following the in situ conversion process, treatment area 424 may becooled by introducing water to produce steam from the hot portion of theformation. Introduction of water to produce steam may vaporize somehydrocarbons remaining in the formation. Water may be injected throughinjection wells 916. The injected water may cool the formation. Theremaining hydrocarbons and generated steam may be produced throughproduction wells 206 and/or heater wells 502. Treatment area 424 may becooled to a temperature near the boiling point of water. The steamproduced from the formation may be used to heat a first fluid used tosolution mine another portion of the formation.

Treatment area 424 may be further cooled to a temperature at which waterwill condense in the formation. Water and/or solvent may be introducedinto and be removed from the treatment area. Removing the condensedwater and/or solvent from treatment area 424 may remove any additionalsoluble material remaining in the treatment area. The water and/orsolvent may entrain non-soluble fluid present in the formation. Fluidmay be pumped out of treatment area 424 through production well 206and/or heater wells 502. The injection and removal of water and/orsolvent may be repeated until a desired water quality within treatmentarea 424 is achieved. Water quality may be measured at injection wells916, heater wells 502, and/or production wells 206. The water qualitymay substantially match or exceed the water quality of treatment area424 prior to treatment.

In some embodiments, treatment area 424 may include a leached zonelocated above an unleached zone. The leached zone may have been leachednaturally and/or by a separate leaching process. In certain embodiments,the unleached zone may be at a depth of at least about 500 m. Athickness of the unleached zone may be between about 100 m and about 500m. However, the depth and thickness of the unleached zone may varydepending on, for example, a location of treatment area 424 and/or thetype of formation. In certain embodiments, the first fluid is injectedinto the unleached zone below the leached zone. Heat may also beprovided into the unleached zone.

In certain embodiments, a section of a formation may be left untreatedby solution mining and/or unleached. The unleached section may beproximate a selected section of the formation that has been leachedand/or solution mined by providing the first fluid as described above.The unleached section may inhibit the flow of water into the selectedsection. In some embodiments, more than one unleached section may beproximate a selected section.

Nahcolite may be present in the formation in layers or beds. In certainembodiments, solution mining layered or bedded nahcolite from theformation causes vertical shifting in the formation. FIG. 240 depicts anembodiment of a formation with nahcolite layers in the formation (beforesolution mining nahcolite from the formation). Hydrocarbon layers 380Ahave substantially no nahcolite and hydrocarbon layers 380B havenahcolite. FIG. 241 depicts the formation of FIG. 240 after thenahcolite has been solution mined. Layers 380B have collapsed due to theremoval of the nahcolite from the layers. The collapsing of layers 380Bcauses compaction of the layers and vertical shifting of the formation.The richness of layers 380B is increased after compaction of the layers.In addition, the permeability of layers 380B may remain relatively highafter compaction due to removal of the nahcolite. Heater wells may beplaced in the formation after removal of nahcolite and the subsequentvertical shifting. Forming heater wellbores and/or installing heaters inthe formation after the vertical shifting protects the heaters frombeing damaged due to the vertical shifting.

In certain embodiments, removing nahcolite from the formationinterconnects two or more wells in the formation. Removing nahcolitefrom zones in the formation may increase the permeability in the zones.Some zones may have more nahcolite than others and become more permeableas the nahcolite is removed. At a certain time, zones with the increasedpermeability may interconnect two or more wells (for example, injectionwells or production wells) in the formation.

FIG. 242 depicts an embodiment of two injection wells interconnected bya zone that has been solution mined to remove nahcolite from the zone.Injection wells 916 are used to solution mine hydrocarbon layer 380,which contains nahcolite. During the initial portion of the solutionmining process, injection wells 916 are used to inject water and/orother fluids, and to produce dissolved nahcolite fluids from theformation. Each injection well 916 is used to inject water and producefluid from a near wellbore region as the permeability of hydrocarbonlayer is not sufficient to allow fluid to flow between the injectionwells. In certain embodiments, zone 1572 has more nahcolite than otherportions of hydrocarbon layer 380. With increased nahcolite removal fromzone 1572, the permeability of the zone may increase. The permeabilityincreases from the wellbores outwards as nahcolite is removed from zone1572. At some point during solution mining of the formation, thepermeability of zone 1572 increases to allow injection wells 916 tobecome interconnected such that fluid will flow between the wells. Atthis time, one injection well 916 may be used to inject water while theother injection well 916 is used to produce fluids from the formation ina continuous process. Injecting in one well and producing from a secondwell may be more economical and more efficient in removing nahcolite, ascompared to injecting and producing through the same well. In someembodiments, additional wells may be drilled into zone 1572 and/orhydrocarbon layer 380 in addition to injection wells 916. The additionalwells may be used to circulate additional water and/or to produce fluidsfrom the formation. The wells may later be used as heater wells and/orproduction wells for the in situ conversion process treatment ofhydrocarbon layer 380.

In some embodiments, the second fluid produced from the formation duringsolution mining is used to produce sodium bicarbonate. Sodiumbicarbonate may be used in the food and pharmaceutical industries, inleather tanning, in fire retardation, in wastewater treatment, and influe gas treatment (flue gas desulphurization and hydrogen chloridereduction). The second fluid may be kept pressurized and at an elevatedtemperature when removed from the formation. The second fluid may becooled in a crystallizer to precipitate sodium bicarbonate.

In some embodiments, the second fluid produced from the formation duringsolution mining is used to produce sodium carbonate. Sodium carbonatemay be used in the manufacture of glass, in the manufacture ofdetergents, in water purification, polymer production, tanning, papermanufacturing, effluent neutralization, metal refining, sugarextraction, and/or cement manufacturing. The second fluid removed fromthe formation may be heated in a treatment facility to form sodiumcarbonate (soda ash) and/or sodium carbonate brine. Heating sodiumbicarbonate will form sodium carbonate according to the equation:2NaHCO₃→Na₂CO₃+CO₂+H₂O.  (80)

In certain embodiments, the heat for heating the sodium bicarbonate isprovided using heat from the formation. For example, a heat exchangerthat uses steam produced from the water introduced into the hotformation may be used to heat the second fluid to dissociationtemperatures of the sodium bicarbonate. In some embodiments, the secondfluid is circulated through the formation to utilize heat in theformation for further reaction. Steam and/or hot water may also be addedto facilitate circulation. In some embodiments, the second fluid iscirculated through conduits previously used to heat the formation.

In some embodiments, higher temperatures are used in the formation (forexample, above about 120° C., above about 130° C., above about 150° C.,or below about 250° C.) during solution mining of nahcolite. The firstfluid is introduced into the formation under pressure sufficient toinhibit sodium bicarbonate from dissociating to produce carbon dioxide.The pressure in the formation may be maintained at sufficiently highpressures to inhibit such nahcolite dissociation but below pressuresthat would result in fracturing the formation. In addition, the pressurein the formation may be maintained high enough to inhibit steamformation if hot water is being introduced in the formation. In someembodiments, a portion of the nahcolite may begin to decompose in situ.In such cases, nahcolite is removed from the formation as soda ash. Ifsoda ash is produced from solution mining of nahcolite, the soda ash maybe transported to a separate facility for treatment. The soda ash may betransported through a pipeline to the separate facility.

As described above, in certain embodiments, following removal ofnahcolite from the formation, the formation is treated using the in situconversion process to produce formation fluids from the formation. Ifdawsonite is present in the formation, dawsonite within the heatedportion of the formation decomposes during heating of the formation topyrolysis temperature. Dawsonite typically decomposes at temperaturesabove 270° C. according to the reaction:2NaAl(OH)₂CO₃→Na₂CO₃+Al₂O₃+2H₂O+CO₂.  (81)

In certain embodiments, alumina formed by dawsonite decomposition issolution mined using a chelating agent. The chelating agent may beinjected through injection wells, production wells, and/or heater wellsused for solution mining nahcolite and/or the in situ conversion process(for example, injection wells 916, production wells 206, and/or heaterwells 502 depicted in FIG. 239). The chelating agent may be an aqueousacid. In certain embodiments, the chelating agent is EDTA(ethylenediaminetetraacetic acid). Other examples of possible chelatingagents include, but are not limited to, ethylenediamine, porphyrins,dimercaprol, nitrilotriacetic acid, diethylenetriaminepentaacetic acid,phosphoric acids, acetic acid, acetoxy benzoic acids, nicotinic acid,pyruvic acid, citric acid, tartaric acid, malonic acid, imidizole,ascorbic acid, phenols, hydroxy ketones, sebacic acid, and boric acid.The mixture of chelating agent and alumina may be produced throughproduction wells or other wells used for solution mining and/or the insitu conversion process (for example, injection wells 916, productionwells 206, and/or heater wells 502, which are depicted in FIG. 239). Thealumina may be separated from the chelating agent in a treatmentfacility. The recovered chelating agent may be recirculated back to theformation to solution mine more alumina.

In some embodiments, alumina within the formation may be solution minedusing a basic fluid after the in situ conversion process. Basic fluidsinclude, but are not limited to, sodium hydroxide, ammonia, magnesiumhydroxide, magnesium carbonate, sodium carbonate, potassium carbonate,pyridine, and amines. In an embodiment, sodium carbonate brine, such as0.5 Normal Na₂CO₃, is used to solution mine alumina. Sodium carbonatebrine may be obtained from solution mining nahcolite from the formation.Obtaining the basic fluid by solution mining the nahcolite maysignificantly reduce costs associated with obtaining the basic fluid.The basic fluid may be injected into the formation through a heater welland/or an injection well. The basic fluid may combine with alumina toform an alumina solution that is removed from the formation. The aluminasolution may be removed through a heater well, injection well, orproduction well.

Alumina may be extracted from the alumina solution in a treatmentfacility. In an embodiment, carbon dioxide is bubbled through thealumina solution to precipitate the alumina from the basic fluid. Carbondioxide may be obtained from dissociation of nahcolite, from the in situconversion process, or from decomposition of the dawsonite during the insitu conversion process.

In certain embodiments, a formation may include portions that aresignificantly rich in either nahcolite or dawsonite only. For example, aformation may contain significant amounts of nahcolite (for example, atleast about 20 weight %, at least about 30 weight %, or at least about40 weight %) in a depocenter of the formation. The depocenter maycontain only about 5 weight % or less dawsonite on average. However, inbottom layers of the formation, a weight percent of dawsonite may beabout 10 weight % or even as high as about 25 weight %. In suchformations, it may be advantageous to solution mine for nahcolite onlyin nahcolite-rich areas, such as the depocenter, and solution mine fordawsonite only in the dawsonite-rich areas, such as the bottom layers.This selective solution mining may significantly reduce fluid costs,heating costs, and/or equipment costs associated with operating thesolution mining process.

In certain formations, dawsonite composition varies between layers inthe formation. For example, some layers of the formation may havedawsonite and some layers may not. In certain embodiments, more heat isprovided to layers with more dawsonite than to layers with lessdawsonite. Tailoring heat input to provide more heat to certaindawsonite layers more uniformly heats the formation as the reaction todecompose dawsonite absorbs some of the heat intended for pyrolyzinghydrocarbons. FIG. 243 depicts an embodiment for heating a formationwith dawsonite in the formation. Hydrocarbon layer 380 may be cored toassess the dawsonite composition of the hydrocarbon layer. The mineralcomposition may be assessed using, for example, FTIR (Fourier transforminfrared spectroscopy) or x-ray diffraction. Assessing the corecomposition may also assess the nahcolite composition of the core. Afterassessing the dawsonite composition, heater 880 may be placed inwellbore 910. Heater 880 includes sections to provide more heat tohydrocarbon layers with more dawsonite in the layers (hydrocarbon layers380D). Hydrocarbon layers with less dawsonite (hydrocarbon layers 380C)are provided with less heat by heater 880. Heat output of heater 880 maybe tailored by, for example, adjusting the resistance of the heateralong the length of the heater. In one embodiment, heater 880 is atemperature limited heater, described herein, that has a highertemperature limit (for example, higher Curie temperature) in sectionsproximate layers 380D as compared to the temperature limit (Curietemperature) of sections proximate layers 380C. The resistance of heater880 may also be adjusted by altering the resistive conducting materialsalong the length of the heater to supply a higher energy input (wattsper meter) adjacent to dawsonite rich layers.

Solution mining dawsonite and nahcolite may be relatively simpleprocesses that produce aluminum and soda ash from the formation. In someembodiments, hydrocarbons produced from the formation using the in situconversion process may be fuel for a power plant that produces directcurrent (DC) electricity at or near the site of the in situ conversionoperation. The produced DC electricity may be used on the site toproduce aluminum metal from the alumina using the Hall process. Aluminummetal may be produced from the alumina by melting the alumina in atreatment facility on the site. Generating the DC electricity at thesite may save on costs associated with using hydrotreaters, pipelines,or other treatment facilities associated with transporting and/ortreating hydrocarbons produced from the formation using the in situconversion process.

In some embodiments, a perimeter barrier may be formed around theportion of the formation to be treated. The perimeter barrier mayinhibit migration of formation fluid into or out of the treatment area.The perimeter barrier may be a frozen barrier and/or a grout barrier.After formation of the perimeter barrier, the treatment area may beprocessed to produce desired products.

Formations that include non-hydrocarbon materials may be treated toremove and/or dissolve a portion of the non-hydrocarbon materials from asection of the formation before hydrocarbons are produced from thesection. In some embodiments, the non-hydrocarbon materials are removedby solution mining. Removing a portion of the non-hydrocarbon materialsmay reduce the carbon dioxide generation sources present in theformation. Removing a portion of the non-hydrocarbon materials mayincrease the porosity and/or permeability of the section of theformation. Removing a portion of the non-hydrocarbon materials mayresult in a raised temperature in the section of the formation.

After solution mining, some of the wells in the treatment may beconverted to heater wells, injection wells, and/or production wells. Insome embodiments, additional wells are formed in the treatment area. Thewells may be heater wells, injection wells, and/or production wells.Logging techniques may be employed to assess the physicalcharacteristics, including any vertical shifting resulting from thesolution mining, and/or the composition of material in the formation.Packing, baffles or other techniques may be used to inhibit formationfluid from entering the heater wells. The heater wells may be activatedto heat the formation to a temperature sufficient to support combustion.

One or more production wells may be positioned in permeable sections ofthe treatment area. Production wells may be horizontally and/orvertically oriented. For example, production wells may be positioned inareas of the formation that have a permeability of greater than 5 darcyor 10 darcy. In some embodiments, production wells may be positionednear a perimeter barrier. A production well may allow water andproduction fluids to be removed from the formation. Positioning theproduction well near a perimeter barrier enhances the flow of fluidsfrom the warmer zones of the formation to the cooler zones.

FIG. 244 depicts an embodiment of a process for treating a hydrocarboncontaining formation with a combustion front. Barrier 454 (for example,a frozen barrier or a grout barrier) may be formed around a perimeter oftreatment area 424 of the formation. The footprint defined by thebarrier may have any desired shape such as circular, square,rectangular, polygonal, or irregular shape. Barrier 454 may be formedusing one or more barrier wells 200. The barrier may be any barrierformed to inhibit the flow of fluid into or out of treatment area 424.In some embodiments, barrier 454 may be a double barrier.

Heat may be provided to treatment area 424 through heaters positioned ininjection wells 916. In some embodiments, the heaters in injection wells916 heat formation adjacent to the injections wells to temperaturessufficient to support combustion. Heaters in injection wells 916 mayraise the formation near the injection wells to temperatures from about90° C. to about 120° C. or higher (for example, a temperature of about90° C., 95° C., 100° C., 110° C., or 120° C.).

Injection wells 916 may be used to introduce a combustion fuel, anoxidant, steam and/or a heat transfer fluid into treatment area 424,either before, during, or after heat is provided to the treatment area424 from heaters. In some embodiments, injection wells 916 are incommunication with each other to allow the introduced fluid to flow fromone well to another. Injection wells 916 may be located at positionsthat are relatively far away from perimeter barrier 454. Introducedfluid may cause combustion of hydrocarbons in treatment area 424. Heatfrom the combustion may heat treatment area 424 and mobilize fluidstoward production wells 206.

A temperature of treatment area 424 may be monitored using temperaturemeasurement devices placed in monitoring wells and/or temperaturemeasurement devices in injection wells 916, production wells 206, and/orheater wells.

In some embodiments, a controlled amount of oxidant (for example, airand/or oxygen) is provided in injection wells 916 to advance a heatfront towards production wells 206. The amount of oxidant is controlledto limit the advancement rate of the heat front and to limit thetemperature of the heat front. The advancing heat front may pyrolyzehydrocarbons. The high permeability in the formation allows thepyrolyzed hydrocarbons to spread in the formation towards productionwells without being overtaken by the advancing heat front.

Vaporized formation fluid and/or gas formed during the combustionprocess may be removed through gas wells 1574 and/or injection well 916.Venting of gases through the gas wells and/or the injection well mayforce the combustion front in a desired direction.

In some embodiments, the formation may be heated to a temperaturesufficient temperature to cause pyrolysis of the formation fluid by thesteam and/or heat transfer fluid. The steam and/or heat transfer fluidmay be heated to temperatures of about 300° C., about 400° C., about500° C., or about 600° C. In certain embodiments, the steam and/or heattransfer fluid may be co-injected with the fuel and/or oxidant.

FIG. 245 depicts a representation of a cross-sectional view of anembodiment for treating a hydrocarbon containing formation with acombustion front. As the combustion front is initiated and/or fueledthrough injection well 916, formation fluid near periphery 1576 of thecombustion front becomes mobile and flow towards production well 206located proximate barrier 454. Combustion products and noncondensableformation fluid may be removed from the formation through gas wells1574. Condensable formation fluid may be produced through productionwell 206. In some embodiments, production well 206 is located belowinjection well 916. Production well 206 may be about, or above 1 m, 5 m,to 10 m below injection well 916. Production well 206 may include aperforated liner that allows hydrocarbons to flow into the productionwell.

Carbon dioxide and/or hydrogen sulfide may be produced during in situconversion processes and during many conventional production processes.Removal of hydrogen sulfide from produced formation fluid may reduce thetoxicity and/or strong odor in the produced formation fluid, thus makingthe formation fluid more acceptable for transportation and/orprocessing. Removing carbon dioxide and/or hydrogen sulfide fromproduced formation fluids may reduce capital costs associated withremoving the fluids and reduce or eliminate the need for certain surfacefacilities (for example, a Claus plant or Scot gas treater). Sincecarbon dioxide has a low heating value, removal of carbon dioxide fromformation fluids may increase the heat capacity of a gas streamseparated from the formation fluid.

Net release of carbon dioxide to the atmosphere and/or hydrogen sulfideconversion to sulfur from an in situ conversion process for hydrocarbonsmay be reduced by utilizing the produced carbon dioxide and/or bystoring carbon dioxide and/or hydrogen sulfide within the formation orwithin another formation. In certain embodiments, carbon dioxide and/orhydrogen sulfide is stored in a deep saline, porous formation. Thecarbon dioxide and/or hydrogen sulfide may promote mineralization withinthe formation. In certain embodiments, carbon dioxide is stored at adepth in the formation such that the carbon dioxide is introduced in theformation in a supercritical state. The depths of outlets of insertionwells used to introduce carbon dioxide and/or hydrogen sulfide in theformation may be 900 m or more below the surface.

Injection of carbon dioxide and/or hydrogen sulfide into a non-producingformation or using the carbon dioxide and/or hydrogen sulfide as a floodfluid is described by Caroll in “Physical Properties Relevant to AcidGas Injection,” Presented at the 14th International Gas ConventionVenezuelan Gas Processors Association on May 10-12, 2000 in Caracas,Venezuela; “Phase Equilibria Relevant to Acid Gas Injection: Part1-Non-Aqueoues Phase Behaviour Journal of Canadian Petroleum Technology,2002, Vol. 41 No. 6, pp. 1-6; and “Phase Equilibria Relevant to Acid GasInjection: Part 2-Aqueoues Phase Behaviour Journal of Canadian PetroleumTechnology, 2002, Vol. 41, No. 7, pp. 1-5, all of which are incorporatedby reference as if fully set forth herein.

During production of formation fluids from a subsurface formation,carbonic acid may be produced from the reaction of carbon dioxide withwater. Portions of wells made of certain materials, such as carbonsteel, may start to deteriorate (e.g., corrode) in the presence of thecarbonic acid. To inhibit corrosion due to carbonic acid, basicsolutions and/or solvents may be introduced in the wellbore toneutralize and/or dissolve the carbonic acid.

In some embodiments, hydrogen sulfide is introduced into one or morewellbores in a subsurface formation. Introduction of the hydrogensulfide may be performed at pressures below the lithostatic pressure ofthe subsurface formation to inhibit fracturing the formation. Theinjected hydrogen sulfide may form a sulfide layer on metal surfaces ofthe well. Formation of a sulfide layer may inhibit corrosion of themetal surfaces of the well by carbonic acid.

In certain embodiments, an electrical insulator (for example, acentralizer, an insulating layer, the electrical insulator in aninsulated conductor heater, or any other electrical insulator describedherein) includes a material that is fired or cured when heated in thesubsurface. The material may develop desired dielectric or otherelectrical properties and/or physical properties after the material isfired or cured in a wellbore in the formation. The material may be firedor cured when a heater is turned on in the wellbore and the heater heatsthe material to its firing or curing temperature.

An example of such a material is a ceramic tape available from CompositeDevelopment Technology, Inc. (Lafayette, Colo., U.S.A.). The ceramictape is flexible before it is fired. The ceramic tape obtains itsdielectric properties after firing. After firing, the ceramic tape is ahard-ceramic with good dielectric properties suitable for subsurfaceelectrical heating.

In an embodiment, the ceramic tape is wrapped around an electricalconductor (for example, the conductor of a temperature limited heater).Electrical current may be applied to the electrical conductor to heatthe heater and fire the ceramic tape. In some embodiments, the ceramictape is pre-fired before installation of a heater. The ceramic tape maybe pre-fired using, for example, a hot gas gun.

Before firing, the ceramic tape is flexible and easy to install in avariety of applications. In certain embodiments, the ceramic tape isused between centralizers in a conductor-in-conduit heater. The ceramictape may inhibit shorting of the conductor and conduit if thecentralizers fail (for example, if the centralizers buckle and fail). Incertain embodiments, the ceramic tape is used as the centralizers in aconductor-in-conduit heater. In some embodiments, the ceramic tape isused as the electrical insulator in an insulated conductor heater. Insome embodiments, the ceramic tape is used as the electrical insulatorin splices between sections of heaters. In some embodiments, the ceramictape is used to electrically insulate the legs of a three-phase heater.The three legs of the three-phase heater may be enclosed in one sheathwith the ceramic tape separating the legs of the heater.

In this patent, certain U.S. patents, U.S. patent applications, andother materials (for example, articles) have been incorporated byreference. The text of such U.S. patents, U.S. patent applications, andother materials is, however, only incorporated by reference to theextent that no conflict exists between such text and the otherstatements and drawings set forth herein. In the event of such conflict,then any such conflicting text in such incorporated by reference U.S.patents, U.S. patent applications, and other materials is specificallynot incorporated by reference in this patent.

Further modifications and alternative embodiments of various aspects ofthe invention may be apparent to those skilled in the art in view ofthis description. Accordingly, this description is to be construed asillustrative only and is for the purpose of teaching those skilled inthe art the general manner of carrying out the invention. It is to beunderstood that the forms of the invention shown and described hereinare to be taken as the presently preferred embodiments. Elements andmaterials may be substituted for those illustrated and described herein,parts and processes may be reversed, and certain features of theinvention may be utilized independently, all as would be apparent to oneskilled in the art after having the benefit of this description of theinvention. Changes may be made in the elements described herein withoutdeparting from the spirit and scope of the invention as described in thefollowing claims. In addition, it is to be understood that featuresdescribed herein independently may, in certain embodiments, be combined.

1. A heater configured for heating a subsurface formation, comprising: an inner electrical conductor comprising electrically conductive material; a ferromagnetic conductor concentric with the inner electrical conductor, wherein the ferromagnetic conductor at least partially surrounds the inner electrical conductor and is electrically coupled to the inner electrical conductor; and an electrical conductor concentric with the ferromagnetic conductor and the inner electrical conductor, wherein the electrical conductor at least partially surrounds the ferromagnetic conductor and is electrically coupled to the ferromagnetic conductor and the inner electrical conductor, the ferromagnetic conductor being positioned relative to the electrical conductor and having a thickness such that an electromagnetic field produced by time-varying current flow in the ferromagnetic conductor confines a majority of the flow of the electrical current to the electrical conductor at temperatures below a selected temperature; wherein the heater is located in a wellbore in a hydrocarbon containing layer in the subsurface formation, the heater is at least about 10 m in length in the hydrocarbon containing layer, and the heater is configured to provide heat to at least a portion of the hydrocarbon containing layer surrounding the wellbore.
 2. The heater of claim 1, wherein the inner electrical conductor is a substantially circular inner conductor.
 3. The heater of claim 1, wherein the inner electrical conductor comprises copper.
 4. The heater of claim 1, further comprising a support member located between the ferromagnetic conductor and the electrical conductor, the support member being concentric with the ferromagnetic conductor and the electrical conductor.
 5. The heater of claim 1, further comprising a support member located inside the inner electrical conductor, the support member being concentric with the inner electrical conductor.
 6. The heater of claim 1, further comprising a support member, wherein the support member is configured to provide the heater with a creep-rupture lifetime of at least about 30,000 hours at operating temperatures up to about 834° C.
 7. The heater of claim 1, wherein the heater has a creep-rupture lifetime of at least about 30,000 hours at operating temperatures up to about 770° C.
 8. The heater of claim 1, wherein the heater is at least about 100 m in length in the hydrocarbon containing layer.
 9. The heater of claim 1, wherein the heater is at least about 300 m in length in the hydrocarbon containing layer.
 10. The heater of claim 1, wherein the heater is configured to provide heat to at least a portion of the hydrocarbon containing layer surrounding the wellbore to mobilize hydrocarbons in the portion.
 11. The heater of claim 1, wherein the heater is configured to provide heat to at least a portion of the hydrocarbon containing layer surrounding the wellbore to pyrolyze hydrocarbons in the portion.
 12. The heater of claim 1, wherein the heater is substantially circular in shape.
 13. The heater of claim 1, wherein the selected temperature is the Curie temperature of the ferromagnetic conductor.
 14. The heater of claim 1, wherein a cross-sectional area of the electrical conductor is at least ½ of a cross-sectional area of the inner electrical conductor.
 15. The heater of claim 1, wherein the electrical conductor provides a majority of a resistive heat output of the heater at temperatures up to approximately the selected temperature of the ferromagnetic conductor.
 16. A heater configured for heating a subsurface formation, comprising: an electrical conductor coupled to a ferromagnetic material and an inner electrical conductor, the heater being configured to provide electric resistance heating, and the heater having dimensions such that a majority of the electric resistance heat output is generated in the electrical conductor; wherein the ferromagnetic material is configured to substantially concentrate time-varying electrical current flow to the electrical conductor at temperatures below a selected temperature; wherein the electrical conductor at least partially surrounds the ferromagnetic material and the ferromagnetic material at least partially surrounds the inner electrical conductor, the inner electrical conductor being substantially circular and the ferromagnetic material and the electrical conductor being concentric with the inner electrical conductor; and wherein the heater is located in a wellbore in a hydrocarbon containing layer in the subsurface formation, the heater is at least about 10 m in length in the hydrocarbon containing layer, and the heater is configured to provide heat to at least a portion of the hydrocarbon containing layer surrounding the wellbore.
 17. The heater of claim 16, wherein the inner electrical conductor is a substantially circular inner conductor.
 18. The heater of claim 16, wherein the inner electrical conductor comprises copper.
 19. The heater of claim 16, further comprising a support member located between the ferromagnetic conductor and the electrical conductor, the support member being concentric with the ferromagnetic conductor and the electrical conductor.
 20. The heater of claim 16, further comprising a support member located inside the inner electrical conductor, the support member being concentric with the inner electrical conductor.
 21. The heather of claim 16, further comprising a support member, wherein the support member is configured to provide the heater with a creep-rupture lifetime of at least about 30,000 hours at operating temperatures up to about 834° C.
 22. The heater of claim 16, wherein the heater has a creep-rupture lifetime of at least about 30,000 hours at operating temperatures up to about 770° C.
 23. The heater of claim 16, wherein the heater is at least about 100 m in length in the hydrocarbon containing layer.
 24. The heater of claim 16, wherein the heater is at least about 300 m in length in the hydrocarbon containing layer.
 25. The heater of claim 16, wherein the heater is configured to provide heat to at least a portion of the hydrocarbon containing layer surrounding the wellbore to mobilize hydrocarbons in the portion.
 26. The heater of claim 16, wherein the heater is configured to provide heat to at least a portion of the hydrocarbon containing layer surrounding the wellbore to pyrolyze hydrocarbons in the portion.
 27. The heater of claim 16, wherein the heater is substantially circular in shape.
 28. The heater of claim 16, wherein the selected temperature is the Curie temperature of the ferromagnetic conductor.
 29. The heater of claim 16, wherein the ferromagnetic member and the electrical conductor are electrically coupled such that a power factor of the heater remains above 0.85 during use of the heater.
 30. The heater of claim 16, wherein a cross-sectional area of the electrical conductor is at least ½ of a cross-sectional area of the inner electrical conductor.
 31. The heater of claim 16, wherein the electrical conductor provides a majority of a resistive heat output of the heater at temperatures up to approximately the selected temperature of the ferromagnetic conductor. 